An oil shale formation may be treated using an in situ thermal process. A mixture of hydrocarbons, H2, and/or other formation fluids may be produced from the formation. Heat may be applied to the formation to raise a temperature of a portion of the formation to a desired temperature. In some embodiments,...http://www.google.com/patents/US20030131993?utm_source=gb-gplus-sharePatent US20030131993 - In situ thermal processing of an oil shale formation with a selected property

In situ thermal processing of an oil shale formation with a selected propertyUS 20030131993 A1

Abstract

An oil shale formation may be treated using an in situ thermal process. A mixture of hydrocarbons, H2, and/or other formation fluids may be produced from the formation. Heat may be applied to the formation to raise a temperature of a portion of the formation to a desired temperature. In some embodiments, the formation to be treated may be selected based on formation characterisitics.

Images(242)

Claims(7441)

What is claimed is:

1. A method of treating an oil shale formation in situ, comprising:

providing heat from one or more heat sources to at least one portion of the formation;

allowing the heat to transfer from the one or more heat sources to a selected section of the formation;

controlling the heat from the one or more heat sources such that an average temperature within at least a majority of the selected section of the formation is less than about 375° C.; and

producing a mixture from the formation.

2. The method of claim 1, wherein the one or more heat sources comprise at least two heat sources, and wherein superposition of heat from at least the two heat sources pyrolyzes at least some hydrocarbons within the selected section of the formation.

3. The method of claim 1, wherein controlling formation conditions comprises maintaining a temperature within the selected section within a pyrolysis temperature range.

4. The method of claim 1, wherein the one or more heat sources comprise electrical heaters.

5. The method of claim 1, wherein the one or more heat sources comprise surface burners.

6. The method of claim 1, wherein the one or more heat sources comprise flameless distributed combustors.

7. The method of claim 1, wherein the one or more heat sources comprise natural distributed combustors.

8. The method of claim 1, further comprising controlling a pressure and a temperature within at least a majority of the selected section of the formation, wherein the pressure is controlled as a function of temperature, or the temperature is controlled as a function of pressure.

9. The method of claim 1, further comprising controlling a pressure within at least a majority of the selected section of the formation with a valve coupled to at least one of the one or more heat sources.

10. The method of claim 1, further comprising controlling a pressure within at least a majority of the selected section of the formation with a valve coupled to a production well located in the formation.

11. The method of claim 1, further comprising controlling the heat such that an average heating rate of the selected section is less than about 1° C. per day during pyrolysis.

12. The method of claim 1, wherein providing heat from the one or more heat sources to at least the portion of formation comprises:

heating a selected volume (V) of the oil shale formation from the one or more heat sources, wherein the formation has an average heat capacity(Cv), and wherein the heating pyrolyzes at least some hydrocarbons within the selected volume of the formation; and

wherein heating energy/day provided to the volume is equal to or less than Pwr, wherein Pwr is calculated by the equation:

Pwr=h*V*Cv*ρB

wherein Pwr is the heating energy/day, h is an average heating rate of the formation, ρB is formation bulk density, and wherein the heating rate is less than about 10° C./day.

13. The method of claim 1, wherein allowing the heat to transfer from the one or more heat sources to the selected section comprises transferring heat substantially by conduction.

14. The method of claim 1, wherein providing heat from the one or more heat sources comprises heating the selected section such that a thermal conductivity of at least a portion of the selected section is greater than about 0.5 W/(m ° C.).

15. The method of claim 1, wherein the produced mixture comprises condensable hydrocarbons having an API gravity of at least about 25°.

16. The method of claim 1, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 0.1% by weight to about 15% by weight of the condensable hydrocarbons are olefins.

17. The method of claim 1, wherein the produced mixture comprises non-condensable hydrocarbons, and wherein a molar ratio of ethene to ethane in the non-condensable hydrocarbons ranges from about 0.001 to about 0.15.

18. The method of claim 1, wherein the produced mixture comprises non-condensable hydrocarbons, and wherein about 0.1% by weight to about 15% by weight of the non-condensable hydrocarbons are olefins.

19. The method of claim 1, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is nitrogen.

20. The method of claim 1, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is oxygen.

21. The method of claim 1, wherein the produced mixture comprises condensable hydrocarbons, wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons comprise oxygen containing compounds, and wherein the oxygen containing compounds comprise phenols.

22. The method of claim 1, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is sulfur.

23. The method of claim 1, wherein the produced mixture comprises condensable hydrocarbons, and wherein greater than about 20% by weight of the condensable hydrocarbons are aromatic compounds.

24. The method of claim 1, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 5% by weight of the condensable hydrocarbons comprises multi-ring aromatics with more than two rings.

25. The method of claim 1, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 0.3% by weight of the condensable hydrocarbons are asphaltenes.

26. The method of claim 1, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons are cycloalkanes.

27. The method of claim 1, wherein the produced mixture comprises a non-condensable component, wherein the non-condensable component comprises hydrogen, and wherein greater than about 10% by volume of the non-condensable component comprises hydrogen and wherein the hydrogen is less than about 80% by volume of the non-condensable component.

28. The method of claim 1, wherein the produced mixture comprises ammonia, and wherein greater than about 0.05% by weight of the produced mixture is ammonia.

29. The method of claim 1, wherein the produced mixture comprises ammonia, and wherein the ammonia is used to produce fertilizer.

30. The method of claim 1, further comprising controlling a pressure within at least a majority of the selected section of the formation, wherein the controlled pressure is at least about 2.0 bars absolute.

31. The method of claim 1, further comprising controlling formation conditions such that the produced mixture comprises a partial pressure of H2 within the mixture greater than about 0.5 bars.

32. The method of claim 31, wherein the partial pressure of H2 is measured when the mixture is at a production well.

33. The method of claim 1, wherein controlling formation conditions comprises recirculating a portion of hydrogen from the mixture into the formation.

34. The method of claim 1, further comprising altering a pressure within the formation to inhibit production of hydrocarbons from the formation having carbon numbers greater than about 25.

35. The method of claim 1, further comprising:

providing hydrogen (H2) to the heated section to hydrogenate hydrocarbons within the section; and

heating a portion of the section with heat from hydrogenation.

36. The method of claim 1, wherein the produced mixture comprises hydrogen and condensable hydrocarbons, the method further comprising hydrogenating a portion of the produced condensable hydrocarbons with at least a portion of the produced hydrogen.

37. The method of claim 1, wherein allowing the heat to transfer comprises increasing a permeability of a majority of the selected section to greater than about 100 millidarcy.

38. The method of claim 1, wherein allowing the heat to transfer comprises substantially uniformly increasing a permeability of a majority of the selected section.

39. The method of claim 1, further comprising controlling the heat to yield greater than about 60% by weight of condensable hydrocarbons, as measured by Fischer Assay.

40. The method of claim 1, wherein producing the mixture comprises producing the mixture in a production well, and wherein at least about 7 heat sources are disposed in the formation for each production well.

41. The method of claim 40, wherein at least about 20 heat sources are disposed in the formation for each production well.

42. The method of claim 1, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, and wherein the unit of heat sources comprises a triangular pattern.

43. The method of claim 1, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, wherein the unit of heat sources comprises a triangular pattern, and wherein a plurality of the units are repeated over an area of the formation to form a repetitive pattern of units.

44. The method of claim 1, further comprising separating the produced mixture into a gas stream and a liquid stream.

45. The method of claim 1, further comprising separating the produced mixture into a gas stream and a liquid stream and separating the liquid stream into an aqueous stream and a non-aqueous stream.

46. The method of claim 1, wherein the produced mixture comprises H2S, the method further comprising separating a portion of the H2S from non-condensable hydrocarbons.

47. The method of claim 1, wherein the produced mixture comprises CO2, the method further comprising separating a portion of the CO2 from non-condensable hydrocarbons.

48. The method of claim 1, wherein the mixture is produced from a production well, wherein the heating is controlled such that the mixture can be produced from the formation as a vapor.

49. The method of claim 1, wherein the mixture is produced from a production well, the method further comprising heating a wellbore of the production well to inhibit condensation of the mixture within the wellbore.

50. The method of claim 1, wherein the mixture is produced from a production well, wherein a wellbore of the production well comprises a heater element configured to heat the formation adjacent to the wellbore, and further comprising heating the formation with the heater element to produce the mixture, wherein the mixture comprises a large non-condensable hydrocarbon gas component and H2.

51. The method of claim 1, wherein the minimum pyrolysis temperature is about 270° C.

52. The method of claim 1, further comprising maintaining the pressure within the formation above about 2.0 bars absolute to inhibit production of fluids having carbon numbers above 25.

53. The method of claim 1, further comprising controlling pressure within the formation in a range from about atmospheric pressure to about 100 bars, as measured at a wellhead of a production well, to control an amount of condensable hydrocarbons within the produced mixture, wherein the pressure is reduced to increase production of condensable hydrocarbons, and wherein the pressure is increased to increase production of non-condensable hydrocarbons.

54. The method of claim 1, further comprising controlling pressure within the formation in a range from about atmospheric pressure to about 100 bars, as measured at a wellhead of a production well, to control an API gravity of condensable hydrocarbons within the produced mixture, wherein the pressure is reduced to decrease the API gravity, and wherein the pressure is increased to reduce the API gravity.

55. A method of treating an oil shale formation in situ, comprising:

providing heat from one or more heat sources to at least a portion of the formation;

allowing the heat to transfer from at least the portion to a selected section of the formation substantially by conduction of heat;

pyrolyzing at least some hydrocarbons within the selected section of the formation; and

producing a mixture from the formation.

56. The method of claim 55, wherein the one or more heat sources comprise at least two heat sources, and wherein superposition of heat from at least the two heat sources pyrolyzes at least some hydrocarbons within the selected section of the formation.

57. The method of claim 55, wherein the one or more heat sources comprise electrical heaters.

58. The method of claim 55, wherein the one or more heat sources comprise surface burners.

59. The method of claim 55, wherein the one or more heat sources comprise flameless distributed combustors.

60. The method of claim 55, wherein the one or more heat sources comprise natural distributed combustors.

61. The method of claim 55, further comprising controlling a pressure and a temperature within at least a majority of the selected section of the formation, wherein the pressure is controlled as a function of temperature, or the temperature is controlled as a function of pressure.

62. The method of claim 55, further comprising controlling the heat such that an average heating rate of the selected section is less than about 1.0° C. per day during pyrolysis.

63. The method of claim 55, wherein providing heat from the one or more heat sources to at least the portion of formation comprises:

heating a selected volume (V) of the oil shale formation from the one or more heat sources, wherein the formation has an average heat capacity (Cv), and wherein the heating pyrolyzes at least some hydrocarbons within the selected volume of the formation; and

wherein heating energy/day provided to the volume is equal to or less than Pwr, wherein Pwr is calculated by the equation:

Pwr=h*V*Cv*ρB

wherein Pwr is the heating energy/day, h is an average heating rate of the formation, ρB is formation bulk density, and wherein the heating rate is less than about 10° C./day.

64. The method of claim 55, wherein providing heat from the one or more heat sources comprises heating the selected section such that a thermal conductivity of at least a portion of the selected section is greater than about 0.5 W/(m ° C.).

65. The method of claim 55, wherein the produced mixture comprises condensable hydrocarbons having an API gravity of at least about 25°.

66. The method of claim 55, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 0.1% by weight to about 15% by weight of the condensable hydrocarbons are olefins.

67. The method of claim 55, wherein the produced mixture comprises non-condensable hydrocarbons, and wherein a molar ratio of ethene to ethane in the non-condensable hydrocarbons ranges from about 0.001 to about 0.15.

68. The method of claim 55, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is nitrogen.

69. The method of claim 55, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is oxygen.

70. The method of claim 55, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is sulfur.

71. The method of claim 55, wherein the produced mixture comprises condensable hydrocarbons, wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons comprise oxygen containing compounds, and wherein the oxygen containing compounds comprise phenols.

72. The method of claim 55, wherein the produced mixture comprises condensable hydrocarbons, and wherein greater than about 20% by weight of the condensable hydrocarbons are aromatic compounds.

73. The method of claim 55, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 5% by weight of the condensable hydrocarbons comprises multi-ring aromatics with more than two rings.

74. The method of claim 55, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 0.3% by weight of the condensable hydrocarbons are asphaltenes.

75. The method of claim 55, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons are cycloalkanes.

76. The method of claim 55, wherein the produced mixture comprises a non-condensable component, wherein the non-condensable component comprises hydrogen, wherein the hydrogen is greater than about 10% by volume of the non-condensable component, and wherein the hydrogen is less than about 80% by volume of the non-condensable component.

77. The method of claim 55, wherein the produced mixture comprises ammonia, and wherein greater than about 0.05% by weight of the produced mixture is ammonia.

78. The method of claim 55, wherein the produced mixture comprises ammonia, and wherein the ammonia is used to produce fertilizer.

79. The method of claim 55, further comprising controlling a pressure within at least a majority of the selected section of the formation, wherein the controlled pressure is at least about 2.0 bars absolute.

80. The method of claim 55, further comprising controlling formation conditions to produce a mixture of condensable hydrocarbons and H2, wherein a partial pressure of H2 within the mixture is greater than about 0.5 bars.

81. The method of claim 80, wherein the partial pressure of H2 is measured when the mixture is at a production well.

82. The method of claim 55, further comprising altering a pressure within the formation to inhibit production of hydrocarbons from the formation having carbon numbers greater than about 25.

83. The method of claim 55, wherein controlling formation conditions comprises recirculating a portion of hydrogen from the mixture into the formation.

84. The method of claim 55, further comprising:

providing hydrogen (H2) to the heated section to hydrogenate hydrocarbons within the section; and

heating a portion of the section with heat from hydrogenation.

85. The method of claim 55, wherein the produced mixture comprises hydrogen and condensable hydrocarbons, the method further comprising hydrogenating a portion of the produced condensable hydrocarbons with at least a portion of the produced hydrogen.

86. The method of claim 55, wherein allowing the heat to transfer comprises increasing a permeability of a majority of the selected section to greater than about 100 millidarcy.

87. The method of claim 55, wherein allowing the heat to transfer comprises substantially uniformly increasing a permeability of a majority of the selected section.

88. The method of claim 55, further comprising controlling the heat to yield greater than about 60% by weight of condensable hydrocarbons, as measured by Fischer Assay.

89. The method of claim 55, wherein producing the mixture comprises producing the mixture in a production well, and wherein at least about 7 heat sources are disposed in the formation for each production well.

90. The method of claim 89, wherein at least about 20 heat sources are disposed in the formation for each production well.

91. The method of claim 55, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, and wherein the unit of heat sources comprises a triangular pattern.

92. The method of claim 55, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, wherein the unit of heat sources comprises a triangular pattern, and wherein a plurality of the units are repeated over an area of the formation to form a repetitive pattern of units.

93. A method of treating an oil shale formation in situ, comprising:

providing heat from one or more heat sources to at least a portion of the formation;

allowing the heat to transfer from the one or more heat sources to a selected section of the formation;

controlling the heat from the one or more heat sources such that an average temperature within at least a majority of the selected section of the formation is less than about 370° C. such that production of a substantial amount of hydrocarbons having carbon numbers greater than 25 is inhibited;

controlling a pressure within at least a majority of the selected section of the formation, wherein the controlled pressure is at least 2.0 bars; and

producing a mixture from the formation, wherein about 0.1% by weight of the produced mixture to about 15% by weight of the produced mixture are olefins, and wherein an average carbon number of the produced mixture is greater than 1 and less than about 25.

94. The method of claim 93, wherein the one or more heat sources comprise at least two heat sources, and wherein superposition of heat from at least the two heat sources pyrolyzes at least some hydrocarbons within the selected section of the formation.

95. The method of claim 93, wherein controlling formation conditions comprises maintaining a temperature within the selected section within a pyrolysis temperature range.

96. The method of claim 93, wherein the one or more heat sources comprise electrical heaters.

97. The method of claim 93, wherein the one or more heat sources comprise surface burners.

98. The method of claim 93, wherein the one or more heat sources comprise flameless distributed combustors.

99. The method of claim 93, wherein the one or more heat sources comprise natural distributed combustors.

100. The method of claim 93, further comprising controlling a pressure and a temperature within at least a majority of the selected section of the formation, wherein the pressure is controlled as a function of temperature, or the temperature is controlled as a function of pressure.

101. The method of claim 93, further comprising controlling the heat such that an average heating rate of the selected section is less than about 1° C. per day during pyrolysis.

102. The method of claim 93, wherein providing heat from the one or more heat sources to at least the portion of formation comprises:

heating a selected volume (V) of the oil shale formation from the one or more heat sources, wherein the formation has an average heat capacity (Cv), and wherein the heating pyrolyzes at least some hydrocarbons within the selected volume of the formation; and

wherein heating energy/day provided to the volume is equal to or less than Pwr, wherein Pwr is calculated by the equation:

Pwr=h*V*Cv*ρB

wherein Pwr is the heating energy/day, h is an average heating rate of the formation, ρB is formation bulk density, and wherein the heating rate is less than about 10° C./day.

104. The method of claim 93, wherein providing heat from the one or more heat sources comprises heating the selected section such that a thermal conductivity of at least a portion of the selected section is greater than about 0.5 W/(m ° C.).

105. The method of claim 93, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 0.1% by weight to about 15% by weight of the condensable hydrocarbons are olefins.

106. The method of claim 93, wherein the produced mixture comprises non-condensable hydrocarbons, and wherein a molar ratio of ethene to ethane in the non-condensable hydrocarbons ranges from about 0.001 to about 0.15.

107. The method of claim 93, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is nitrogen.

108. The method of claim 93, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is oxygen.

109. The method of claim 93, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is sulfur.

110. The method of claim 93, wherein the produced mixture comprises condensable hydrocarbons, wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons comprise oxygen containing compounds, and wherein the oxygen containing compounds comprise phenols.

111. The method of claim 93, wherein the produced mixture comprises condensable hydrocarbons, and wherein greater than about 20% by weight of the condensable hydrocarbons are aromatic compounds.

112. The method of claim 93, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 5% by weight of the condensable hydrocarbons comprises multi-ring aromatics with more than two rings.

113. The method of claim 93, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 0.3% by weight of the condensable hydrocarbons are asphaltenes.

114. The method of claim 93, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons are cycloalkanes.

115. The method of claim 93, wherein the produced mixture comprises a non-condensable component, wherein the non-condensable component comprises hydrogen, wherein the hydrogen is greater than about 10% by volume of the non-condensable component, and wherein the hydrogen is less than about 80% by volume of the non-condensable component.

116. The method of claim 93, wherein the produced mixture comprises ammonia, and wherein greater than about 0.05% by weight of the produced mixture is ammonia.

117. The method of claim 93, wherein the produced mixture comprises ammonia, and wherein the ammonia is used to produce fertilizer.

118. The method of claim 93, further comprising controlling formation conditions to produce a mixture of condensable hydrocarbons and H2, wherein a partial pressure of H2 within the mixture is greater than about 0.5 bars.

119. The method of claim 118, wherein the partial pressure of H2 is measured when the mixture is at a production well.

120. The method of claim 93, further comprising altering a pressure within the formation to inhibit production of hydrocarbons from the formation having carbon numbers greater than about 25.

121. The method of claim 93, further comprising:

providing hydrogen (H2) to the heated section to hydrogenate hydrocarbons within the section; and

heating a portion of the section with heat from hydrogenation.

122. The method of claim 93, wherein the produced mixture comprises hydrogen and condensable hydrocarbons, the method further comprising hydrogenating a portion of the produced condensable hydrocarbons with at least a portion of the produced hydrogen.

123. The method of claim 93, wherein allowing the heat to transfer comprises increasing a permeability of a majority of the selected section to greater than about 100 millidarcy.

124. The method of claim 93, wherein allowing the heat to transfer comprises substantially uniformly increasing a permeability of a majority of the selected section.

125. The method of claim 93, further comprising controlling the heat to yield greater than about 60% by weight of condensable hydrocarbons, as measured by Fischer Assay.

126. The method of claim 93, wherein producing the mixture comprises producing the mixture in a production well, and wherein at least about 7 heat sources are disposed in the formation for each production well.

127. The method of claim 126, wherein at least about 20 heat sources are disposed in the formation for each production well.

128. The method of claim 93, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, and wherein the unit of heat sources comprises a triangular pattern.

129. The method of claim 93, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, wherein the unit of heat sources comprises a triangular pattern, and wherein a plurality of the units are repeated over an area of the formation to form a repetitive pattern of units.

130. The method of claim 93, further comprising separating the produced mixture into a gas stream and a liquid stream.

131. The method of claim 93, further comprising separating the produced mixture into a gas stream and a liquid stream and separating the liquid stream into an aqueous stream and a non-aqueous stream.

132. The method of claim 93, wherein the produced mixture comprises H2S, the method further comprising separating a portion of the H2S from non-condensable hydrocarbons.

133. The method of claim 93, wherein the produced mixture comprises CO2, the method further comprising separating a portion of the CO2 from non-condensable hydrocarbons.

134. The method of claim 93, wherein the mixture is produced from a production well, wherein the heating is controlled such that the mixture can be produced from the formation as a vapor.

135. The method of claim 93, wherein the mixture is produced from a production well, the method further comprising heating a wellbore of the production well to inhibit condensation of the mixture within the wellbore.

136. The method of claim 93, wherein the mixture is produced from a production well, wherein a wellbore of the production well comprises a heater element configured to heat the formation adjacent to the wellbore, and further comprising heating the formation with the heater element to produce the mixture, wherein the produced mixture comprise a large non-condensable hydrocarbon gas component and H2.

137. The method of claim 93, wherein the minimum pyrolysis temperature is about 270° C.

138. The method of claim 93, further comprising maintaining the pressure within the formation above about 2.0 bars absolute to inhibit production of fluids having carbon numbers above 25.

139. The method of claim 93, further comprising controlling pressure within the formation in a range from about atmospheric pressure to about 100 bars absolute, as measured at a wellhead of a production well, to control an amount of condensable fluids within the produced mixture, wherein the pressure is reduced to increase production of condensable fluids, and wherein the pressure is increased to increase production of non-condensable fluids.

140. The method of claim 93, further comprising controlling pressure within the formation in a range from about atmospheric pressure to about 100 bars absolute, as measured at a wellhead of a production well, to control an API gravity of condensable fluids within the produced mixture, wherein the pressure is reduced to decrease the API gravity, and wherein the pressure is increased to reduce the API gravity.

141. A method of treating an oil shale formation in situ, comprising:

providing heat from one or more heat sources to at least a portion of the formation;

allowing the heat to transfer from the one or more heat sources to a selected section of the formation;

controlling a pressure within at least a majority of the selected section of the formation, wherein the controlled pressure is at least about 2.0 bars absolute; and producing a mixture from the formation.

142. The method of claim 141, wherein controlling the pressure comprises controlling the pressure with a valve coupled to at least one of the one or more heat sources.

143. The method of claim 141, wherein controlling the pressure comprises controlling the pressure with a valve coupled to a production well located in the formation.

144. The method of claim 141, wherein the one or more heat sources comprise at least two heat sources, and wherein superposition of heat from at least the two heat sources pyrolyzes at least some hydrocarbons within the selected section of the formation.

145. The method of claim 141, wherein controlling formation conditions comprises maintaining a temperature within the selected section within a pyrolysis temperature range.

146. The method of claim 141, wherein the one or more heat sources comprise electrical heaters.

147. The method of claim 141, wherein the one or more heat sources comprise surface burners.

148. The method of claim 141, wherein the one or more heat sources comprise flameless distributed combustors.

149. The method of claim 141, wherein the one or more heat sources comprise natural distributed combustors.

150. The method of claim 141, further comprising controlling a temperature within at least a majority of the selected section of the formation, wherein the pressure is controlled as a function of temperature, or the temperature is controlled as a function of pressure.

151. The method of claim 141, further comprising controlling the heat such that an average heating rate of the selected section is less than about 1° C. per day during pyrolysis.

152. The method of claim 141, wherein providing heat from the one or more heat sources to at least the portion of formation comprises:

heating a selected volume (V) of the oil shale formation from the one or more heat sources, wherein the formation has an average heat capacity (Cv), and wherein the heating pyrolyzes at least some hydrocarbons within the selected volume of the formation; and

wherein heating energy/day provided to the volume is equal to or less than Pwr, wherein Pwr is calculated by the equation:

Pwr=h*V*Cv*ρB

wherein Pwr is the heating energy/day, h is an average heating rate of the formation, ρB is formation bulk density, and wherein the heating rate is less than about 10° C./day.

154. The method of claim 141, wherein providing heat from the one or more heat sources comprises heating the selected section such that a thermal conductivity of at least a portion of the selected section is greater than about 0.5 W/(m ° C.).

155. The method of claim 141, wherein the produced mixture comprises condensable hydrocarbons having an API gravity of at least about 25°.

156. The method of claim 141, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 0.1% by weight to about 15% by weight of the condensable hydrocarbons are olefins.

157. The method of claim 141, wherein the produced mixture comprises non-condensable hydrocarbons, and wherein a molar ratio of ethene to ethane in the non-condensable hydrocarbons ranges from about 0.001 to about 0.15.

158. The method of claim 141, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is nitrogen.

159. The method of claim 141, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is oxygen.

160. The method of claim 141, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is sulfur.

161. The method of claim 141, wherein the produced mixture comprises condensable hydrocarbons, wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons comprise oxygen containing compounds, and wherein the oxygen containing compounds comprise phenols.

162. The method of claim 141, wherein the produced mixture comprises condensable hydrocarbons, and wherein greater than about 20% by weight of the condensable hydrocarbons are aromatic compounds.

163. The method of claim 141, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 5% by weight of the condensable hydrocarbons comprises multi-ring aromatics with more than two rings.

164. The method of claim 141, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 0.3% by weight of the condensable hydrocarbons are asphaltenes.

165. The method of claim 141, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons are cycloalkanes.

166. The method of claim 141, wherein the produced mixture comprises a non-condensable component, wherein the non-condensable component comprises hydrogen, wherein the hydrogen is greater than about 10% by volume of the non-condensable component, and wherein the hydrogen is less than about 80% by volume of the non-condensable component.

167. The method of claim 141, wherein the produced mixture comprises ammonia, and wherein greater than about 0.05% by weight of the produced mixture is ammonia.

168. The method of claim 141, wherein the produced mixture comprises ammonia, and wherein the ammonia is used to produce fertilizer.

169. The method of claim 141, further comprising controlling formation conditions to produce a mixture of condensable hydrocarbons and H2, wherein a partial pressure of H2 within the mixture is greater than about 0.5 bars.

170. The method of claim 169, wherein the partial pressure of H2 is measured when the mixture is at a production well.

171. The method of claim 141, further comprising altering a pressure within the formation to inhibit production of hydrocarbons from the formation having carbon numbers greater than about 25.

172. The method of claim 141, wherein controlling formation conditions comprises recirculating a portion of hydrogen from the mixture into the formation.

173. The method of claim 141, further comprising:

providing hydrogen (H2) to the heated section to hydrogenate hydrocarbons within the section; and

heating a portion of the section with heat from hydrogenation.

174. The method of claim 141, wherein the produced mixture comprises hydrogen and condensable hydrocarbons, the method further comprising hydrogenating a portion of the produced condensable hydrocarbons with at least a portion of the produced hydrogen.

175. The method of claim 141, wherein allowing the heat to transfer comprises increasing a permeability of a majority of the selected section to greater than about 100 millidarcy.

176. The method of claim 141, wherein allowing the heat to transfer comprises substantially uniformly increasing a permeability of a majority of the selected section.

177. The method of claim 141, further comprising controlling the heat to yield greater than about 60% by weight of condensable hydrocarbons, as measured by Fischer Assay.

178. The method of claim 141, wherein producing the mixture from the formation comprises producing the mixture in a production well, and wherein at least about 7 heat sources are disposed in the formation for each production well.

179. The method of claim 178, wherein at least about 20 heat sources are disposed in the formation for each production well.

180. A method of treating an oil shale formation in situ, comprising:

providing heat from one or more heat sources to at least a portion of the formation;

allowing the heat to transfer from the one or more heat sources to a selected section of the formation; and

controlling a pressure within at least a majority of the selected section of the formation, wherein the controlled pressure is at least about 2.0 bars absolute;

controlling the heat from the one or more heat sources such that an average temperature within at least a majority of the selected section of the formation is less than about 375° C.; and

producing a mixture from the formation.

181. The method of claim 180, wherein the one or more heat sources comprise at least two heat sources, and wherein superposition of heat from at least the two heat sources pyrolyzes at least some hydrocarbons within the selected section of the formation.

182. The method of claim 180, wherein controlling formation conditions comprises maintaining a temperature within the selected section within a pyrolysis temperature range.

183. The method of claim 180, wherein the one or more heat sources comprise electrical heaters.

184. The method of claim 180, wherein the one or more heat sources comprise surface burners.

185. The method of claim 180, wherein the one or more heat sources comprise flameless distributed combustors.

186. The method of claim 180, wherein the one or more heat sources comprise natural distributed combustors.

187. The method of claim 180, further comprising controlling a pressure and a temperature within at least a majority of the selected section of the formation, wherein the pressure is controlled as a function of temperature, or the temperature is controlled as a function of pressure.

188. The method of claim 180, further comprising controlling the heat such that an average heating rate of the selected section is less than about 1° C. per day during pyrolysis.

189. The method of claim 180, wherein providing heat from the one or more heat sources to at least the portion of formation comprises:

heating a selected volume (V) of the oil shale formation from the one or more heat sources, wherein the formation has an average heat capacity (Cv), and wherein the heating pyrolyzes at least some hydrocarbons within the selected volume of the formation; and

wherein heating energy/day provided to the volume is equal to or less than Pwr, wherein Pwr is calculated by the equation:

Pwr=h*V*Cv*ρB

wherein Pwr is the heating energy/day, h is an average heating rate of the formation, ρB is formation bulk density, and wherein the heating rate is less than about 10° C./day.

191. The method of claim 180, wherein providing heat from the one or more heat sources comprises heating the selected section such that a thermal conductivity of at least a portion of the selected section is greater than about 0.5 W/(m ° C.).

192. The method of claim 180, wherein the produced mixture comprises condensable hydrocarbons having an API gravity of at least about 25°.

193. The method of claim 180, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 0.1% by weight to about 15% by weight of the condensable hydrocarbons are olefins.

194. The method of claim 180, wherein the produced mixture comprises non-condensable hydrocarbons, and wherein about 0.1% by weight to about 15% by weight of the non-condensable hydrocarbons are olefins.

195. The method of claim 180, wherein the produced mixture comprises non-condensable hydrocarbons, and wherein a molar ratio of ethene to ethane in the non-condensable hydrocarbons ranges from about 0.001 to about 0.15.

196. The method of claim 180, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is nitrogen.

197. The method of claim 180, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is oxygen.

198. The method of claim 180, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is sulfur.

199. The method of claim 180, wherein the produced mixture comprises condensable hydrocarbons, wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons comprise oxygen containing compounds, and wherein the oxygen containing compounds comprise phenols.

200. The method of claim 180, wherein the produced mixture comprises condensable hydrocarbons, and wherein greater than about 20% by weight of the condensable hydrocarbons are aromatic compounds.

201. The method of claim 180, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 5% by weight of the condensable hydrocarbons comprises multi-ring aromatics with more than two rings.

202. The method of claim 180, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 0.3% by weight of the condensable hydrocarbons are asphaltenes.

203. The method of claim 180, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons are cycloalkanes.

204. The method of claim 180, wherein the produced mixture comprises a non-condensable component, wherein the non-condensable component comprises hydrogen, wherein the hydrogen is greater than about 10% by volume of the non-condensable component, and wherein the hydrogen is less than about 80% by volume of the non-condensable component.

205. The method of claim 180, wherein the produced mixture comprises ammonia, and wherein greater than about 0.05% by weight of the produced mixture is ammonia.

206. The method of claim 180, wherein the produced mixture comprises ammonia, and wherein the ammonia is used to produce fertilizer.

207. The method of claim 180, wherein controlling the heat further comprises controlling the heat such that coke production is inhibited.

208. The method of claim 180, further comprising controlling formation conditions to produce a mixture of condensable hydrocarbons and H2, wherein a partial pressure of H2 within the mixture is greater than about 0.5 bars.

209. The method of claim 208, wherein the partial pressure of H2 is measured when the mixture is at a production well.

210. The method of claim 180, further comprising altering the pressure within the formation to inhibit production of hydrocarbons from the formation having carbon numbers greater than about 25.

211. The method of claim 180, wherein controlling formation conditions comprises recirculating a portion of hydrogen from the mixture into the formation.

212. The method of claim 180, further comprising:

providing hydrogen (H2) to the heated section to hydrogenate hydrocarbons within the section; and

heating a portion of the section with heat from hydrogenation.

213. The method of claim 180, wherein the produced mixture comprises hydrogen and condensable hydrocarbons, the method further comprising hydrogenating a portion of the produced condensable hydrocarbons with at least a portion of the produced hydrogen.

214. The method of claim 180, wherein allowing the heat to transfer comprises increasing a permeability of a majority of the selected section to greater than about 100 millidarcy.

215. The method of claim 180, wherein allowing the heat to transfer comprises substantially uniformly increasing a permeability of a majority of the selected section.

216. The method of claim 180, further comprising controlling the heat to yield greater than about 60% by weight of condensable hydrocarbons, as measured by Fischer Assay.

217. The method of claim 180, wherein producing the mixture comprises producing the mixture in a production well, and wherein at least about 7 heat sources are disposed in the formation for each production well.

218. The method of claim 217, wherein at least about 20 heat sources are disposed in the formation for each production well.

219. The method of claim 180, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, and wherein the unit of heat sources comprises a triangular pattern.

220. The method of claim 180, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, wherein the unit of heat sources comprises a triangular pattern, and wherein a plurality of the units are repeated over an area of the formation to form a repetitive pattern of units

221. A method of treating an oil shale formation in situ, comprising:

providing heat from one or more heat sources to at least a portion of the formation;

allowing the heat to transfer from the one or more heat sources to a selected section of the formation;

producing a mixture from the formation, wherein at least a portion of the mixture is produced during the pyrolysis and the mixture moves through the formation in a vapor phase; and

maintaining a pressure within at least a majority of the selected section above about 2.0 bars absolute.

222. The method of claim 221, wherein the one or more heat sources comprise at least two heat sources, and wherein superposition of heat from at least the two heat sources pyrolyzes at least some hydrocarbons within the selected section of the formation.

223. The method of claim 221, wherein controlling formation conditions comprises maintaining a temperature within the selected section within a pyrolysis temperature range.

224. The method of claim 221, wherein the one or more heat sources comprise electrical heaters.

225. The method of claim 221, wherein the one or more heat sources comprise surface burners.

226. The method of claim 221, wherein the one or more heat sources comprise flameless distributed combustors.

227. The method of claim 221, wherein the one or more heat sources comprise natural distributed combustors.

228. The method of claim 221, further comprising controlling the pressure and a temperature within at least a majority of the selected section of the formation, wherein the pressure is controlled as a function of temperature, or the temperature is controlled as a function of pressure.

229. The method of claim 221, further comprising controlling the heat such that an average heating rate of the selected section is less than about 1° C. per day during pyrolysis.

230. The method of claim 221, wherein providing heat from the one or more heat sources to at least the portion of formation comprises:

heating a selected volume (V) of the oil shale formation from the one or more heat sources, wherein the formation has an average heat capacity (Cv), and wherein the heating pyrolyzes at least some hydrocarbons within the selected volume of the formation; and

wherein heating energy/day provided to the volume is equal to or less than Pwr, wherein Pwr is calculated by the equation:

Pwr=h*V*Cv*ρB

wherein Pwr is the heating energy/day, h is an average heating rate of the formation, ρB is formation bulk density, and wherein the heating rate is less than about 10° C./day.

232. The method of claim 221, wherein providing heat from the one or more heat sources comprises heating the selected section such that a thermal conductivity of at least a portion of the selected section is greater than about 0.5 W/(m ° C.).

233. The method of claim 221, wherein the produced mixture comprises condensable hydrocarbons having an API gravity of at least about 25°.

234. The method of claim 221, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 0.1% by weight to about 15% by weight of the condensable hydrocarbons are olefins.

235. The method of claim 221, wherein the produced mixture comprises non-condensable hydrocarbons, and wherein about 0.1% by weight to about 15% by weight of the non-condensable hydrocarbons are olefins.

236. The method of claim 221, wherein the produced mixture comprises non-condensable hydrocarbons, and wherein a molar ratio of ethene to ethane in the non-condensable hydrocarbons ranges from about 0.001 to about 0.15.

237. The method of claim 221, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is nitrogen.

238. The method of claim 221, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is oxygen.

239. The method of claim 221, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is sulfur.

240. The method of claim 221, wherein the produced mixture comprises condensable hydrocarbons, wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons comprise oxygen containing compounds, and wherein the oxygen containing compounds comprise phenols.

241. The method of claim 221, wherein the produced mixture comprises condensable hydrocarbons, and wherein greater than about 20% by weight of the condensable hydrocarbons are aromatic compounds.

242. The method of claim 221, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 5% by weight of the condensable hydrocarbons comprises multi-ring aromatics with more than two rings.

243. The method of claim 221, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 0.3% by weight of the condensable hydrocarbons are asphaltenes.

244. The method of claim 221, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons are cycloalkanes.

245. The method of claim 221, wherein the produced mixture comprises a non-condensable component, wherein the non-condensable component comprises hydrogen, wherein the hydrogen is greater than about 10% by volume of the non-condensable component, and wherein the hydrogen is less than about 80% by volume of the non-condensable component.

246. The method of claim 221, wherein the produced mixture comprises ammonia, and wherein greater than about 0.05% by weight of the produced mixture is ammonia.

247. The method of claim 221, wherein the produced mixture comprises ammonia, and wherein the ammonia is used to produce fertilizer.

248. The method of claim 221, wherein the pressure is measured at a wellhead of a production well.

249. The method of claim 221, wherein the pressure is measured at a location within a wellbore of the production well.

250. The method of claim 221, wherein the pressure is maintained below about 100 bars absolute.

251. The method of claim 221, further comprising controlling formation conditions to produce a mixture of condensable hydrocarbons and H2, wherein a partial pressure of H2 within the mixture is greater than about 0.5 bars.

252. The method of claim 251, wherein the partial pressure of H2 is measured when the mixture is at a production well.

253. The method of claim 221, further comprising altering a pressure within the formation to inhibit production of hydrocarbons from the formation having carbon numbers greater than about 25.

254. The method of claim 221, wherein controlling formation conditions comprises recirculating a portion of hydrogen from the mixture into the formation.

255. The method of claim 221, further comprising:

providing hydrogen (H2) to the heated section to hydrogenate hydrocarbons within the section; and

heating a portion of the section with heat from hydrogenation.

256. The method of claim 221, wherein the produced mixture comprises hydrogen and condensable hydrocarbons, the method further comprising hydrogenating a portion of the produced condensable hydrocarbons with at least a portion of the produced hydrogen.

257. The method of claim 221, wherein allowing the heat to transfer comprises increasing a permeability of a majority of the selected section to greater than about 100 millidarcy.

258. The method of claim 221, wherein allowing the heat to transfer comprises substantially uniformly increasing a permeability of a majority of the selected section.

259. The method of claim 221, further comprising controlling the heat to yield greater than about 60% by weight of condensable hydrocarbons, as measured by Fischer Assay.

260. The method of claim 221, wherein producing the mixture comprises producing the mixture in a production well, and wherein at least about 7 heat sources are disposed in the formation for each production well.

261. The method of claim 260, wherein at least about 20 heat sources are disposed in the formation for each production well.

262. The method of claim 221, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, and wherein the unit of heat sources comprises a triangular pattern.

263. The method of claim 221, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, wherein the unit of heat sources comprises a triangular pattern, and wherein a plurality of the units are repeated over an area of the formation to form a repetitive pattern of units.

264. A method of treating an oil shale formation in situ, comprising:

providing heat from one or more heat sources to at least a portion of the formation;

allowing the heat to transfer from the one or more heat sources to a selected section of the formation;

maintaining a pressure within at least a majority of the selected section of the formation above 2.0 bars absolute; and

producing a mixture from the formation, wherein the produced mixture comprises condensable hydrocarbons having an API gravity higher than an API gravity of condensable hydrocarbons in a mixture producible from the formation at the same temperature and at atmospheric pressure.

265. The method of claim 264, wherein the one or more heat sources comprise at least two heat sources, and wherein superposition of heat from at least the two heat sources pyrolyzes at least some hydrocarbons within the selected section of the formation.

266. The method of claim 264, wherein controlling formation conditions comprises maintaining a temperature within the selected section within a pyrolysis temperature range.

267. The method of claim 264, wherein the one or more heat sources comprise electrical heaters.

268. The method of claim 264, wherein the one or more heat sources comprise surface burners.

269. The method of claim 264, wherein the one or more heat sources comprise flameless distributed combustors.

270. The method of claim 264, wherein the one or more heat sources comprise natural distributed combustors.

271. The method of claim 264, further comprising controlling the pressure and a temperature within at least a majority of the selected section of the formation, wherein the pressure is controlled as a function of temperature, or the temperature is controlled as a function of pressure.

272. The method of claim 264, further comprising controlling the heat such that an average heating rate of the selected section is less than about 1° C. per day during pyrolysis.

273. The method of claim 264, wherein providing heat from the one or more heat sources to at least the portion of formation comprises:

heating a selected volume (V) of the oil shale formation from the one or more heat sources, wherein the formation has an average heat capacity (Cv), and wherein the heating pyrolyzes at least some hydrocarbons within the selected volume of the formation; and

wherein heating energy/day provided to the volume is equal to or less than Pwr, wherein Pwr is calculated by the equation:

Pwr=h*V*Cv*ρB

wherein Pwr is the heating energy/day, h is an average heating rate of the formation, ρB is formation bulk density, and wherein the heating rate is less than about 10° C./day.

275. The method of claim 264, wherein providing heat from the one or more heat sources comprises heating the selected section such that a thermal conductivity of at least a portion of the selected section is greater than about 0.5 W/(m ° C.).

276. The method of claim 264, wherein the produced mixture comprises condensable hydrocarbons having an API gravity of at least about 25°.

277. The method of claim 264, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 0.1% by weight to about 15% by weight of the condensable hydrocarbons are olefins.

278. The method of claim 264, wherein the produced mixture comprises non-condensable hydrocarbons, and wherein about 0.1% by weight to about 15% by weight of the non-condensable hydrocarbons are olefins.

279. The method of claim 264, wherein the produced mixture comprises non-condensable hydrocarbons, and wherein a molar ratio of ethene to ethane in the non-condensable hydrocarbons ranges from about 0.001 to about 0.15.

280. The method of claim 264, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is nitrogen.

281. The method of claim 264, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is oxygen.

282. The method of claim 264, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is sulfur.

283. The method of claim 264, wherein the produced mixture comprises condensable hydrocarbons, wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons comprise oxygen containing compounds, and wherein the oxygen containing compounds comprise phenols.

284. The method of claim 264, wherein the produced mixture comprises condensable hydrocarbons, and wherein greater than about 20% by weight of the condensable hydrocarbons are aromatic compounds.

285. The method of claim 264, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 5% by weight of the condensable hydrocarbons comprises multi-ring aromatics with more than two rings.

286. The method of claim 264, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 0.3% by weight of the condensable hydrocarbons are asphaltenes.

287. The method of claim 264, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons are cycloalkanes.

288. The method of claim 264, wherein the produced mixture comprises a non-condensable component, wherein the non-condensable component comprises hydrogen, wherein the hydrogen is greater than about 10% by volume of the non-condensable component, and wherein the hydrogen is less than about 80% by volume of the non-condensable component.

289. The method of claim 264, wherein the produced mixture comprises ammonia, and wherein greater than about 0.05% by weight of the produced mixture is ammonia.

290. The method of claim 264, wherein the produced mixture comprises ammonia, and wherein the ammonia is used to produce fertilizer.

291. The method of claim 264, further comprising controlling formation conditions to produce a mixture of condensable hydrocarbons and H2, wherein a partial pressure of H2 within the mixture is greater than about 0.5 bars.

292. The method of claim 264, wherein a partial pressure of H2 is measured when the mixture is at a production well.

293. The method of claim 264, further comprising altering a pressure within the formation to inhibit production of hydrocarbons from the formation having carbon numbers greater than about 25.

294. The method of claim 264, wherein controlling formation conditions comprises recirculating a portion of hydrogen from the mixture into the formation.

295. The method of claim 264, further comprising:

providing hydrogen (H2) to the heated section to hydrogenate hydrocarbons within the section; and

heating a portion of the section with heat from hydrogenation.

296. The method of claim 264, wherein the produced mixture comprises hydrogen and condensable hydrocarbons, the method further comprising hydrogenating a portion of the produced condensable hydrocarbons with at least a portion of the produced hydrogen.

297. The method of claim 264, wherein allowing the heat to transfer comprises increasing a permeability of a majority of the selected section to greater than about 100 millidarcy.

298. The method of claim 264, wherein allowing the heat to transfer comprises substantially uniformly increasing a permeability of a majority of the selected section.

299. The method of claim 264, further comprising controlling the heat to yield greater than about 60% by weight of condensable hydrocarbons, as measured by Fischer Assay.

300. The method of claim 264, wherein producing the mixture comprises producing the mixture in a production well, and wherein at least about 7 heat sources are disposed in the formation for each production well.

301. The method of claim 300, wherein at least about 20 heat sources are disposed in the formation for each production well.

302. The method of claim 264, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, and wherein the unit of heat sources comprises a triangular pattern.

303. The method of claim 264, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, wherein the unit of heat sources comprises a triangular pattern, and wherein a plurality of the units are repeated over an area of the formation to form a repetitive pattern of units.

304. A method of treating an oil shale formation in situ, comprising:

providing heat from one or more heat sources to at least a portion of the formation;

allowing the heat to transfer from the one or more heat sources to a selected section of the formation;

maintaining a pressure within at least a majority of the selected section of the formation to above 2.0 bars absolute; and

producing a fluid from the formation, wherein condensable hydrocarbons within the fluid comprise an atomic hydrogen to atomic carbon ratio of greater than about 1.75.

305. The method of claim 304, wherein the one or more heat sources comprise at least two heat sources, and wherein superposition of heat from at least the two heat sources pyrolyzes at least some hydrocarbons within the selected section of the formation.

306. The method of claim 304, wherein controlling formation conditions comprises maintaining a temperature within the selected section within a pyrolysis temperature range.

307. The method of claim 304, wherein the one or more heat sources comprise electrical heaters.

308. The method of claim 304, wherein the one or more heat sources comprise surface burners.

309. The method of claim 304, wherein the one or more heat sources comprise flameless distributed combustors.

310. The method of claim 304, wherein the one or more heat sources comprise natural distributed combustors.

311. The method of claim 304, further comprising controlling the pressure and a temperature within at least a majority of the selected section of the formation, wherein the pressure is controlled as a function of temperature, or the temperature is controlled as a function of pressure.

312. The method of claim 304, further comprising controlling the heat such that an average heating rate of the selected section is less than about 1° C. per day during pyrolysis.

313. The method of claim 304, wherein providing heat from the one or more heat sources to at least the portion of formation comprises:

heating a selected volume (V) of the oil shale formation from the one or more heat sources, wherein the formation has an average heat capacity (Cv), and wherein the heating pyrolyzes at least some hydrocarbons within the selected volume of the formation; and

wherein heating energy/day provided to the volume is equal to or less than Pwr, wherein Pwr is calculated by the equation:

Pwr=h*V*Cv*ρB

wherein Pwr is the heating energy/day, h is an average heating rate of the formation, ρB is formation bulk density, and wherein the heating rate is less than about 10° C./day.

315. The method of claim 304, wherein providing heat from the one or more heat sources comprises heating the selected section such that a thermal conductivity of at least a portion of the selected section is greater than about 0.5 W/(m ° C.).

316. The method of claim 304, wherein the produced mixture comprises condensable hydrocarbons having an API gravity of at least about 25°.

317. The method of claim 304, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 0.1% by weight to about 15% by weight of the condensable hydrocarbons are olefins.

318. The method of claim 304, wherein the produced mixture comprises non-condensable hydrocarbons, and wherein about 0.1% by weight to about 15% by weight of the non-condensable hydrocarbons are olefins.

319. The method of claim 304, wherein the produced mixture comprises non-condensable hydrocarbons, and wherein a molar ratio of ethene to ethane in the non-condensable hydrocarbons ranges from about 0.001 to about 0.15.

320. The method of claim 304, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is nitrogen.

321. The method of claim 304, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is oxygen.

322. The method of claim 304, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is sulfur.

323. The method of claim 304, wherein the produced mixture comprises condensable hydrocarbons, wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons comprise oxygen containing compounds, and wherein the oxygen containing compounds comprise phenols.

324. The method of claim 304, wherein the produced mixture comprises condensable hydrocarbons, and wherein greater than about 20% by weight of the condensable hydrocarbons are aromatic compounds.

325. The method of claim 304, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 5% by weight of the condensable hydrocarbons comprises multi-ring aromatics with more than two rings.

326. The method of claim 304, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 0.3% by weight of the condensable hydrocarbons are asphaltenes.

327. The method of claim 304, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons are cycloalkanes.

328. The method of claim 304, wherein the produced mixture comprises a non-condensable component, wherein the non-condensable component comprises hydrogen, wherein the hydrogen is greater than about 10% by volume of the non-condensable component, and wherein the hydrogen is less than about 80% by volume of the non-condensable component.

329. The method of claim 304, wherein the produced mixture comprises ammonia, and wherein greater than about 0.05% by weight of the produced mixture is ammonia.

330. The method of claim 304, wherein the produced mixture comprises ammonia, and wherein the ammonia is used to produce fertilizer.

331. The method of claim 304, further comprising controlling formation conditions to produce a mixture of condensable hydrocarbons and H2, wherein a partial pressure of H2 within the mixture is greater than about 0.5 bars.

332. The method of claim 304, wherein a partial pressure of H2 is measured when the mixture is at a production well.

333. The method of claim 304, further comprising altering the pressure within the formation to inhibit production of hydrocarbons from the formation having carbon numbers greater than about 25.

334. The method of claim 304, wherein controlling formation conditions comprises recirculating a portion of hydrogen from the mixture into the formation.

335. The method of claim 304, further comprising:

providing hydrogen (H2) to the heated section to hydrogenate hydrocarbons within the section; and

heating a portion of the section with heat from hydrogenation.

336. The method of claim 304, wherein the produced mixture comprises hydrogen and condensable hydrocarbons, the method further comprising hydrogenating a portion of the produced condensable hydrocarbons with at least a portion of the produced hydrogen.

337. The method of claim 304, wherein allowing the heat to transfer comprises increasing a permeability of a majority of the selected section to greater than about 100 millidarcy.

338. The method of claim 304, wherein allowing the heat to transfer comprises substantially uniformly increasing a permeability of a majority of the selected section.

339. The method of claim 304, further comprising controlling the heat to yield greater than about 60% by weight of condensable hydrocarbons, as measured by Fischer Assay.

340. The method of claim 304, wherein producing the mixture comprises producing the mixture in a production well, and wherein at least about 7 heat sources are disposed in the formation for each production well.

341. The method of claim 340, wherein at least about 20 heat sources are disposed in the formation for each production well.

342. The method of claim 304, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, and wherein the unit of heat sources comprises a triangular pattern.

343. The method of claim 304, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, wherein the unit of heat sources comprises a triangular pattern, and wherein a plurality of the units are repeated over an area of the formation to form a repetitive pattern of units.

344. A method of treating an oil shale formation in situ, comprising:

providing heat from one or more heat sources to at least a portion of the formation;

allowing the heat to transfer from the one or more heat sources to a selected section of the formation;

maintaining a pressure within at least a majority of the selected section of the formation to above 2.0 bars absolute; and

producing a mixture from the formation, wherein the produced mixture comprises a higher amount of non-condensable components as compared to non-condensable components producible from the formation under the same temperature conditions and at atmospheric pressure.

345. The method of claim 344, wherein the one or more heat sources comprise at least two heat sources, and wherein superposition of heat from at least the two heat sources pyrolyzes at least some hydrocarbons within the selected section of the formation.

346. The method of claim 344, wherein controlling formation conditions comprises maintaining a temperature within the selected section within a pyrolysis temperature range.

347. The method of claim 344, wherein the one or more heat sources comprise electrical heaters.

348. The method of claim 344, wherein the one or more heat sources comprise surface burners.

349. The method of claim 344, wherein the one or more heat sources comprise flameless distributed combustors.

350. The method of claim 344, wherein the one or more heat sources comprise natural distributed combustors.

351. The method of claim 344, further comprising controlling the pressure and a temperature within at least a majority of the selected section of the formation, wherein the pressure is controlled as a function of temperature, or the temperature is controlled as a function of pressure.

352. The method of claim 344, further comprising controlling the heat such that an average heating rate of the selected section is less than about 1° C. per day during pyrolysis.

353. The method of claim 344, wherein providing heat from the one or more heat sources to at least the portion of formation comprises:

heating a selected volume (V) of the oil shale formation from the one or more heat sources, wherein the formation has an average heat capacity (Cv), and wherein the heating pyrolyzes at least some hydrocarbons within the selected volume of the formation; and

wherein heating energy/day provided to the volume is equal to or less than Pwr, wherein Pwr is calculated by the equation:

Pwr=h*V*Cv*ρB

wherein Pwr is the heating energy/day, h is an average heating rate of the formation, ρB is formation bulk density, and wherein the heating rate is less than about 10° C./day.

355. The method of claim 344, wherein providing heat from the one or more heat sources comprises heating the selected section such that a thermal conductivity of at least a portion of the selected section is greater than about 0.5 W/(m ° C.).

356. The method of claim 344, wherein the produced mixture comprises condensable hydrocarbons having an API gravity of at least about 25°.

357. The method of claim 344, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 0.1% by weight to about 15% by weight of the condensable hydrocarbons are olefins.

358. The method of claim 344, wherein the produced mixture comprises non-condensable hydrocarbons, and wherein about 0.1% by weight to about 15% by weight of the non-condensable hydrocarbons are olefins.

359. The method of claim 344, wherein the produced mixture comprises non-condensable hydrocarbons, and wherein a molar ratio of ethene to ethane in the non-condensable hydrocarbons ranges from about 0.001 to about 0.15.

360. The method of claim 344, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is nitrogen.

361. The method of claim 344, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is oxygen.

362. The method of claim 344, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is sulfur.

363. The method of claim 344, wherein the produced mixture comprises condensable hydrocarbons, wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons comprise oxygen containing compounds, and wherein the oxygen containing compounds comprise phenols.

364. The method of claim 344, wherein the produced mixture comprises condensable hydrocarbons, and wherein greater than about 20% by weight of the condensable hydrocarbons are aromatic compounds.

365. The method of claim 344, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 5% by weight of the condensable hydrocarbons comprises multi-ring aromatics with more than two rings.

366. The method of claim 344, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 0.3% by weight of the condensable hydrocarbons are asphaltenes.

367. The method of claim 344, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons are cycloalkanes.

368. The method of claim 344, wherein the produced mixture comprises a non-condensable component, wherein the non-condensable component comprises hydrogen, wherein the hydrogen is greater than about 10% by volume of the non-condensable component, and wherein the hydrogen is less than about 80% by volume of the non-condensable component.

369. The method of claim 344, wherein the produced mixture comprises ammonia, and wherein greater than about 0.05% by weight of the produced mixture is ammonia.

370. The method of claim 344, wherein the produced mixture comprises ammonia, and wherein the ammonia is used to produce fertilizer.

371. The method of claim 344, further comprising controlling formation conditions to produce a mixture of condensable hydrocarbons and H2, wherein a partial pressure of H2 within the mixture is greater than about 0.5 bars.

372. The method of claim 344, wherein a partial pressure of H2 is measured when the mixture is at a production well.

373. The method of claim 344, further comprising altering the pressure within the formation to inhibit production of hydrocarbons from the formation having carbon numbers greater than about 25.

374. The method of claim 344, further comprising:

providing hydrogen (H2) to the heated section to hydrogenate hydrocarbons within the section; and

heating a portion of the section with heat from hydrogenation.

375. The method of claim 344, wherein the produced mixture comprises hydrogen and condensable hydrocarbons, the method further comprising hydrogenating a portion of the produced condensable hydrocarbons with at least a portion of the produced hydrogen.

376. The method of claim 344, wherein allowing the heat to transfer comprises increasing a permeability of a majority of the selected section to greater than about 100 millidarcy.

377. The method of claim 344, wherein allowing the heat to transfer comprises substantially uniformly increasing a permeability of a majority of the selected section.

378. The method of claim 344, further comprising controlling the heat to yield greater than about 60% by weight of condensable hydrocarbons, as measured by Fischer Assay.

379. The method of claim 344, wherein producing the mixture comprises producing the mixture in a production well, and wherein at least about 7 heat sources are disposed in the formation for each production well.

380. The method of claim 379, wherein at least about 20 heat sources are disposed in the formation for each production well.

381. The method of claim 344, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, and wherein the unit of heat sources comprises a triangular pattern.

382. The method of claim 344, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, wherein the unit of heat sources comprises a triangular pattern, and wherein a plurality of the units are repeated over an area of the formation to form a repetitive pattern of units.

383. A method of treating an oil shale formation in situ, comprising:

providing heat from one or more heat sources to at least a portion of the formation;

allowing the heat to transfer from the one or more heat sources to a selected section of the formation such that superimposed heat from the one or more heat sources pyrolyzes at least about 20% by weight of hydrocarbons within the selected section of the formation; and

producing a mixture from the formation.

384. The method of claim 383, wherein the one or more heat sources comprise at least two heat sources, and wherein superposition of heat from at least the two heat sources pyrolyzes at least some hydrocarbons within the selected section of the formation.

385. The method of claim 383, wherein controlling formation conditions comprises maintaining a temperature within the selected section within a pyrolysis temperature range.

386. The method of claim 383, wherein the one or more heat sources comprise electrical heaters.

387. The method of claim 383, wherein the one or more heat sources comprise surface burners.

388. The method of claim 383, wherein the one or more heat sources comprise flameless distributed combustors.

389. The method of claim 383, wherein the one or more heat sources comprise natural distributed combustors.

390. The method of claim 383, further comprising controlling a pressure and a temperature within at least a majority of the selected section of the formation, wherein the pressure is controlled as a function of temperature, or the temperature is controlled as a function of pressure.

391. The method of claim 383, further comprising controlling the heat such that an average heating rate of the selected section is less than about 1° C. per day during pyrolysis.

392. The method of claim 383, wherein providing heat from the one or more heat sources to at least the portion of formation comprises:

heating a selected volume (V) of the oil shale formation from the one or more heat sources, wherein the formation has an average heat capacity (Cv), and wherein the heating pyrolyzes at least some hydrocarbons within the selected volume of the formation; and

wherein heating energy/day provided to the volume is equal to or less than Pwr, wherein Pwr is calculated by the equation:

Pwr=h*V*Cv*ρB

wherein Pwr is the heating energy/day, h is an average heating rate of the formation, ρB is formation bulk density, and wherein the heating rate is less than about 10° C./day.

394. The method of claim 383, wherein providing heat from the one or more heat sources comprises heating the selected formation such that a thermal conductivity of at least a portion of the selected section is greater than about 0.5 W/(m ° C.).

395. The method of claim 383, wherein the produced mixture comprises condensable hydrocarbons having an API gravity of at least about 25°.

396. The method of claim 383, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 0.1% by weight to about 15% by weight of the condensable hydrocarbons are olefins.

397. The method of claim 383, wherein the produced mixture comprises non-condensable hydrocarbons, and wherein about 0.1% by weight to about 15% by weight of the non-condensable hydrocarbons are olefins.

398. The method of claim 383, wherein the produced mixture comprises non-condensable hydrocarbons, and wherein a molar ratio of ethene to ethane in the non-condensable hydrocarbons ranges from about 0.001 to about 0.15.

399. The method of claim 383, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is nitrogen.

400. The method of claim 383, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is oxygen.

401. The method of claim 383, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is sulfur.

402. The method of claim 383, wherein the produced mixture comprises condensable hydrocarbons, wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons comprise oxygen containing compounds, and wherein the oxygen containing compounds comprise phenols.

403. The method of claim 383, wherein the produced mixture comprises condensable hydrocarbons, and wherein greater than about 20% by weight of the condensable hydrocarbons are aromatic compounds.

404. The method of claim 383, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 5% by weight of the condensable hydrocarbons comprise multi-ring aromatics wit more than two rings.

405. The method of claim 383, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 0.3% by weight of the condensable hydrocarbons are asphaltenes.

406. The method of claim 383, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons are cycloalkanes.

407. The method of claim 383, wherein the produced mixture comprises a non-condensable component, wherein the non-condensable component comprises hydrogen, wherein the hydrogen is greater than about 10% by volume of the non-condensable component, and wherein the hydrogen is less than about 80% by volume of the non-condensable component.

408. The method of claim 383, wherein the produced mixture comprises ammonia, and wherein greater than about 0.05% by weight of the produced mixture is ammonia.

409. The method of claim 383, wherein the produced mixture comprises ammonia, and wherein the ammonia is used to produce fertilizer.

410. The method of claim 383, further comprising controlling a pressure within at least a majority of the selected section of the formation, wherein the controlled pressure is at least about 2.0 bars absolute.

411. The method of claim 383, further comprising controlling formation conditions to produce a mixture of condensable hydrocarbons and H2, wherein a partial pressure of H2 within the mixture is greater than about 0.5 bars.

412. The method of claim 383, wherein a partial pressure of H2 is measured when the mixture is at a production well.

413. The method of claim 383, further comprising altering a pressure within the formation to inhibit production of hydrocarbons from the formation having carbon numbers greater than about 25.

414. The method of claim 383, wherein controlling formation conditions comprises recirculating a portion of hydrogen from the mixture into the formation.

415. The method of claim 383, further comprising:

providing hydrogen (H2) to the heated section to hydrogenate hydrocarbons within the section; and

heating a portion of the section with heat from hydrogenation.

416. The method of claim 383, wherein the produced mixture comprises hydrogen and condensable hydrocarbons, the method further comprising hydrogenating a portion of the produced condensable hydrocarbons with at least a portion of the produced hydrogen.

417. The method of claim 383, wherein allowing the heat to transfer comprises increasing a permeability of a majority of the selected section to greater than about 100 millidarcy.

418. The method of claim 383, wherein allowing the heat to transfer comprises substantially uniformly increasing a permeability of a majority of the selected section.

419. The method of claim 383, further comprising controlling the heat to yield greater than about 60% by weight of condensable hydrocarbons, as measured by Fischer Assay.

420. The method of claim 383, wherein producing the mixture comprises producing the mixture in a production well, and wherein at least about 7 heat sources are disposed in the formation for each production well.

421. The method of claim 420, wherein at least about 20 heat sources are disposed in the formation for each production well.

422. The method of claim 383, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, and wherein the unit of heat sources comprises a triangular pattern.

423. The method of claim 383, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, wherein the unit of heat sources comprises a triangular pattern, and wherein a plurality of the units are repeated over an area of the formation to form a repetitive pattern of units.

424. A method of treating an oil shale formation in situ, comprising:

providing heat from one or more heat sources to at least a portion of the formation;

allowing the heat to transfer from the one or more heat sources to a selected section of the formation such that superimposed heat from the one or more heat sources pyrolyzes at least about 20% of hydrocarbons within the selected section of the formation; and

producing a mixture from the formation, wherein the mixture comprises a condensable component having an API gravity of at least about 25°.

425. The method of claim 424, wherein the one or more heat sources comprise at least two heat sources, and wherein superposition of heat from at least the two heat sources pyrolyzes at least some hydrocarbons within the selected section of the formation.

426. The method of claim 424, wherein controlling formation conditions comprises maintaining a temperature within the selected section within a pyrolysis temperature range.

427. The method of claim 424, wherein the one or more heat sources comprise electrical heaters.

428. The method of claim 424, wherein the one or more heat sources comprise surface burners.

429. The method of claim 424, wherein the one or more heat sources comprise flameless distributed combustors.

430. The method of claim 424, wherein the one or more heat sources comprise natural distributed combustors.

431. The method of claim 424, further comprising controlling a pressure and a temperature within at least a majority of the selected section of the formation, wherein the pressure is controlled as a function of temperature, or the temperature is controlled as a function of pressure.

432. The method of claim 424, further comprising controlling the heat such that an to average heating rate of the selected section is less than about 1° C. per day during pyrolysis.

433. The method of claim 424, wherein providing heat from the one or more heat sources to at least the portion of formation comprises:

heating a selected volume (V) of the oil shale formation from the one or more heat sources, wherein the formation has an average heat capacity (Cv), and wherein the heating pyrolyzes at least some hydrocarbons within the selected volume of the formation; and

wherein heating energy/day provided to the volume is equal to or less than Pwr, wherein Pwr is calculated by the equation:

Pwr=h*V*Cv*ρB

wherein Pwr is the heating energy/day, h is an average heating rate of the formation, ρB is formation bulk density, and wherein the heating rate is less than about 10° C./day.

435. The method of claim 424, wherein providing heat from the one or more heat sources comprises heating the selected section such that a thermal conductivity of at least a portion of the selected section is greater than about 0.5 W/(m ° C.).

436. The method of claim 424, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 0.1% by weight to about 15% by weight of the condensable hydrocarbons are olefins.

437. The method of claim 424, wherein the produced mixture comprises non-condensable hydrocarbons, and wherein about 0.1% by weight to about 15% by weight of the non-condensable hydrocarbons are olefins.

438. The method of claim 424, wherein the produced mixture comprises non-condensable hydrocarbons, and wherein a molar ratio of ethene to ethane in the non-condensable hydrocarbons ranges from about 0.001 to about 0.15.

439. The method of claim 424, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is nitrogen.

440. The method of claim 424, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is oxygen.

441. The method of claim 424, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is sulfur.

442. The method of claim 424, wherein the produced mixture comprises condensable hydrocarbons, wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons comprise oxygen containing compounds, and wherein the oxygen containing compounds comprise phenols.

443. The method of claim 424, wherein the produced mixture comprises condensable hydrocarbons, and wherein greater than about 20% by weight of the condensable hydrocarbons are aromatic compounds.

444. The method of claim 424, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 5% by weight of the condensable hydrocarbons comprises multi-ring aromatics with more than two rings.

445. The method of claim 424, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 0.3% by weight of the condensable hydrocarbons are asphaltenes.

446. The method of claim 424, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 5% by weight to about 30% by weight of the At condensable hydrocarbons are cycloalkanes.

447. The method of claim 424, wherein the produced mixture comprises a non-condensable component, wherein the non-condensable component comprises hydrogen, wherein the hydrogen is greater than about 10% by volume of the non-condensable component, and wherein the hydrogen is less than about 80% by volume of the non-condensable component.

448. The method of claim 424, wherein the produced mixture comprises ammonia, and wherein greater than about 0.05% by weight of the produced mixture is ammonia.

449. The method of claim 424, wherein the produced mixture comprises ammonia, and wherein the ammonia is used to produce fertilizer.

450. The method of claim 424, further comprising controlling a pressure within at least a majority of the selected section of the formation, wherein the controlled pressure is at least about 2.0 bars absolute.

451. The method of claim 424, further comprising controlling formation conditions to produce a mixture of condensable hydrocarbons and H2, wherein a partial pressure of H2 within the mixture is greater than about 0.5 bars.

452. The method of claim 424, wherein a partial pressure of H2 is measured when the mixture is at a production well.

453. The method of claim 424, further comprising altering a pressure within the formation to inhibit production of hydrocarbons from the formation having carbon numbers greater than about 25.

454. The method of claim 424, wherein controlling formation conditions comprises recirculating a portion of hydrogen from the mixture into the formation.

455. The method of claim 424, further comprising:

providing hydrogen (H2) to the heated section to hydrogenate hydrocarbons within the section; and

heating a portion of the section with heat from hydrogenation.

456. The method of claim 424, wherein the produced mixture comprises hydrogen and condensable hydrocarbons, the method further comprising hydrogenating a portion of the produced condensable hydrocarbons with at least a portion of the produced hydrogen.

457. The method of claim 424, wherein allowing the heat to transfer comprises increasing a permeability of a majority of the selected section to greater than about 100 millidarcy.

458. The method of claim 424, wherein allowing the heat to transfer comprises substantially uniformly increasing a permeability of a majority of the selected section.

459. The method of claim 424, further comprising controlling the heat to yield greater than about 60% by weight of condensable hydrocarbons, as measured by Fischer Assay.

460. The method of claim 424, wherein producing the mixture comprises producing the mixture in a production well, and wherein at least about 7 heat sources are disposed in the formation for each production well.

461. The method of claim 460, wherein at least about 20 heat sources are disposed in the formation for each production well.

462. The method of claim 424, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, and wherein the unit of heat sources comprises a triangular pattern.

463. The method of claim 424, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, wherein the unit of heat sources comprises a triangular pattern, and wherein a plurality of the units are repeated over an area of the formation to form a repetitive pattern of units.

464. A method of treating a layer of an oil shale formation in situ, comprising:

providing heat from one or more heat sources to at least a portion of the layer, wherein the one or more heat sources are positioned proximate an edge of the layer;

allowing the heat to transfer from the one or more heat sources to a selected section of the layer such that superimposed heat from the one or more heat sources pyrolyzes at least some hydrocarbons within the selected section of the formation; and

producing a mixture from the formation.

465. The method of claim 464, wherein the one or more heat sources are laterally spaced from a center of the layer.

466. The method of claim 464, wherein the one or more heat sources are positioned in a staggered line.

467. The method of claim 464, wherein the one or more heat sources positioned proximate the edge of the layer can increase an amount of hydrocarbons produced per unit of energy input to the one or more heat sources.

468. The method of claim 464, wherein the one or more heat sources positioned proximate the edge of the layer can increase the volume of formation undergoing pyrolysis per unit of energy input to the one or more heat sources.

469. The method of claim 464, wherein the one or more heat sources comprise electrical heaters.

470. The method of claim 464, wherein the one or more heat sources comprise surface burners.

471. The method of claim 464, wherein the one or more heat sources comprise flameless distributed combustors.

472. The method of claim 464, wherein the one or more heat sources comprise natural distributed combustors.

473. The method of claim 464, further comprising controlling a pressure and a temperature within at least a majority of the selected section of the formation, wherein the pressure is controlled as a function of temperature, or the temperature is controlled as a function of pressure.

474. The method of claim 464, further comprising controlling the heat such that an average heating rate of the selected section is less than about 1.0° C. per day during pyrolysis.

475. The method of claim 464, wherein providing heat from the one or more heat sources to at least the portion of the layer comprises:

heating a selected volume (V) of the oil shale formation from the one or more heat sources, wherein the formation has an average heat capacity (Cv), and wherein the heating pyrolyzes at least some hydrocarbons within the selected volume of the formation; and

wherein heating energy/day provided to the volume is equal to or less than Pwr, wherein Pwr is calculated by the equation:

Pwr=h*V*Cv*ρB

wherein Pwr is the heating energy/day, h is an average heating rate of the formation, ρB is formation bulk density, and wherein the heating rate is less than about 10° C./day.

476. The method of claim 464, wherein providing heat from the one or more heat sources comprises heating the selected section such that a thermal conductivity of at least a portion of the selected section is greater than about 0.5 W/(m ° C.).

477. The method of claim 464, wherein the produced mixture comprises condensable hydrocarbons having an API gravity of at least about 25°.

478. The method of claim 464, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 0.1% by weight to about 15% by weight of the condensable hydrocarbons are olefins.

479. The method of claim 464, wherein the produced mixture comprises non-condensable hydrocarbons, and wherein a molar ratio of ethene to ethane in the non-condensable hydrocarbons ranges from about 0.001 to about 0.15.

480. The method of claim 464, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is nitrogen.

481. The method of claim 464, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is oxygen.

482. The method of claim 464, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is sulfur.

483. The method of claim 464, wherein the produced mixture comprises condensable hydrocarbons, wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons comprise oxygen containing compounds, and wherein the oxygen containing compounds comprise phenols.

484. The method of claim 464, wherein the produced mixture comprises condensable hydrocarbons, and wherein greater than about 20% by weight of the condensable hydrocarbons are aromatic compounds.

485. The method of claim 464, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 5% by weight of the condensable hydrocarbons comprises multi-ring aromatics with more than two rings.

486. The method of claim 464, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 0.3% by weight of the condensable hydrocarbons are asphaltenes.

487. The method of claim 464, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons are cycloalkanes.

488. The method of claim 464, wherein the produced mixture comprises a non-condensable component, wherein the non-condensable component comprises hydrogen, wherein the hydrogen is greater than about 10% by volume of the non-condensable component, and wherein the hydrogen is less than about 80% by volume of the non-condensable component.

489. The method of claim 464, wherein the produced mixture comprises ammonia, and wherein greater than about 0.05% by weight of the produced mixture is ammonia.

490. The method of claim 464, wherein the produced mixture comprises ammonia, and wherein the ammonia is used to produce fertilizer.

491. The method of claim 464, further comprising controlling a pressure within at least a majority of the selected section of the formation, wherein the controlled pressure is at least about 2.0 bars absolute.

492. The method of claim 464, further comprising controlling formation conditions to produce a mixture of condensable hydrocarbons and H2, wherein a partial pressure of H2 within the mixture is greater than about 0.5 bars.

493. The method of claim 492, wherein the partial pressure of H2 is measured when the mixture is at a production well.

494. The method of claim 464, further comprising altering a pressure within the formation to inhibit production of hydrocarbons from the formation having carbon numbers greater than about 25.

495. The method of claim 464, further comprising controlling formation conditions, wherein controlling formation conditions comprises recirculating a portion of hydrogen from the mixture into the formation.

496. The method of claim 464, further comprising:

providing hydrogen (H2) to the heated section to hydrogenate hydrocarbons within the section; and

heating a portion of the section with heat from hydrogenation.

497. The method of claim 464, wherein the produced mixture comprises hydrogen and condensable hydrocarbons, the method further comprising hydrogenating a portion of the produced condensable hydrocarbons with at least a portion of the produced hydrogen.

498. The method of claim 464, wherein allowing the heat to transfer comprises increasing a permeability of a majority of the selected section to greater than about 100 millidarcy.

499. The method of claim 464, wherein allowing the heat to transfer comprises substantially uniformly increasing a permeability of a majority of the selected section.

500. The method of claim 464, further comprising controlling the heat to yield greater than about 60% by weight of condensable hydrocarbons, as measured by Fischer Assay.

501. The method of claim 464, wherein producing the mixture comprises producing the mixture in a production well, and wherein at least about 7 heat sources are disposed in the formation for each production well.

502. The method of claim 501, wherein at least about 20 heat sources are disposed in the formation for each production well.

503. The method of claim 464, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, and wherein the unit of heat sources comprises a triangular pattern.

504. The method of claim 464, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, wherein the unit of heat sources comprises a triangular pattern, and wherein a plurality of the units are repeated over an area of the formation to form a repetitive pattern of units.

505. A method of treating an oil shale formation in situ, comprising:

providing heat from one or more heat sources to at least a portion of the formation;

allowing the heat to transfer from the one or more heat sources to a selected section of the formation; and

controlling a pressure and a temperature within at least a majority of the selected section of the formation, wherein the pressure is controlled as a function of temperature, or the temperature is controlled as a function of pressure; and

producing a mixture from the formation.

506. The method of claim 505, wherein the one or more heat sources comprise at least two heat sources, and wherein superposition of heat from at least the two heat sources pyrolyzes at least some hydrocarbons within the selected section of the formation.

507. The method of claim 505, wherein controlling formation conditions comprises maintaining a temperature within the selected section within a pyrolysis temperature range.

508. The method of claim 505, wherein the one or more heat sources comprise electrical heaters.

509. The method of claim 505, wherein the one or more heat sources comprise surface burners.

510. The method of claim 505, wherein the one or more heat sources comprise flameless distributed combustors.

511. The method of claim 505, wherein the one or more heat sources comprise natural distributed combustors.

512. The method of claim 505, further comprising controlling the heat such that an average heating rate of the selected section is less than about 1° C. per day during pyrolysis.

513. The method of claim 505, wherein providing heat from the one or more heat sources to at least the portion of formation comprises:

heating a selected volume (V) of the oil shale formation from the one or more heat sources, wherein the formation has an average heat capacity (Cv), and wherein the heating pyrolyzes at least some hydrocarbons within the selected volume of the formation; and

wherein heating energy/day provided to the volume is equal to or less than Pwr, wherein Pwr is calculated by the equation:

Pwr=h*V*Cv*ρB

wherein Pwr is the heating energy/day, h is an average heating rate of the formation, ρB is formation bulk density, and wherein the heating rate is less than about 10° C./day.

515. The method of claim 505, wherein providing heat from the one or more heat sources comprises heating the selected section such that a thermal conductivity of at least a portion of the selected section is greater than about 0.5 W/(m ° C.).

516. The method of claim 505, wherein the produced mixture comprises condensable hydrocarbons having an API gravity of at least about 25°.

517. The method of claim 505, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 0.1% by weight to about 15% by weight of the condensable hydrocarbons are olefins.

518. The method of claim 505, wherein the produced mixture comprises non-condensable hydrocarbons, and wherein about 0.1% by weight to about 15% by weight of the non-condensable hydrocarbons are olefins.

519. The method of claim 505, wherein the produced mixture comprises non-condensable hydrocarbons, and wherein a molar ratio of ethene to ethane in the non-condensable hydrocarbons ranges from about 0.001 to about 0.15.

520. The method of claim 505, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is nitrogen.

521. The method of claim 505, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is oxygen.

522. The method of claim 505, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is sulfur.

523. The method of claim 505, wherein the produced mixture comprises condensable hydrocarbons, wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons comprise oxygen containing compounds, and wherein the oxygen containing compounds comprise phenols.

524. The method of claim 505, wherein the produced mixture comprises condensable hydrocarbons, and wherein greater than about 20% by weight of the condensable hydrocarbons are aromatic compounds.

525. The method of claim 505, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 5% by weight of the condensable hydrocarbons comprises multi-ring aromatics with more than two rings.

526. The method of claim 505, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 0.3% by weight of the condensable hydrocarbons are asphaltenes.

527. The method of claim 505, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons are cycloalkanes.

528. The method of claim 505, wherein the produced mixture comprises a non-condensable component, wherein the non-condensable component comprises hydrogen, wherein the hydrogen is greater than about 10% by volume of the non-condensable component, and wherein the hydrogen is less than about 80% by volume of the non-condensable component.

529. The method of claim 505, wherein the produced mixture comprises ammonia, and wherein greater than about 0.05% by weight of the produced mixture is ammonia.

530. The method of claim 505, wherein the produced mixture comprises ammonia, and wherein the ammonia is used to produce fertilizer.

531. The method of claim 505, wherein the controlled pressure is at least about 2.0 bars absolute.

532. The method of claim 505, further comprising controlling formation conditions to produce a mixture of condensable hydrocarbons and H2, wherein a partial pressure of H2 within the mixture is greater than about 0.5 bars.

533. The method of claim 505, wherein a partial pressure of H2 is measured when the mixture is at a production well.

534. The method of claim 505, further comprising altering a pressure within the formation to inhibit production of hydrocarbons from the formation having carbon numbers greater than about 25.

535. The method of claim 505, wherein controlling formation conditions comprises recirculating a portion of hydrogen from the mixture into the formation.

536. The method of claim 505, further comprising:

providing hydrogen (H2) to the heated section to hydrogenate hydrocarbons within the section; and

heating a portion of the section with heat from hydrogenation.

537. The method of claim 505, wherein the produced mixture comprises hydrogen and condensable hydrocarbons, the method further comprising hydrogenating a portion of the produced condensable hydrocarbons with at least a portion of the produced hydrogen.

538. The method of claim 505, wherein allowing the heat to transfer comprises increasing a permeability of a majority of the selected section to greater than about 100 millidarcy.

539. The method of claim 505, wherein allowing the heat to transfer comprises substantially uniformly increasing a permeability of a majority of the selected section.

540. The method of claim 505, further comprising controlling the heat to yield greater than about 60% by weight of condensable hydrocarbons, as measured by Fischer Assay.

541. The method of claim 505, wherein producing the mixture comprises producing the mixture in a production well, and wherein at least about 7 heat sources are disposed in the formation for each production well.

542. The method of claim 541, wherein at least about 20 heat sources are disposed in the formation for each production well.

543. The method of claim 505, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, and wherein the unit of heat sources comprises a triangular pattern.

544. The method of claim 505, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, wherein the unit of heat sources comprises a triangular pattern, and wherein a plurality of the units are repeated over an area of the formation to form a repetitive pattern of units.

545. A method of treating an oil shale formation in situ, comprising:

providing heat from one or more heat sources to at least a portion of the formation;

allowing the heat to transfer from the one or more heat sources to a selected section of the formation to raise an average temperature within the selected section to, or above, a temperature that will pyrolyze hydrocarbons within the selected section;

producing a mixture from the formation; and

controlling API gravity of the produced mixture to be greater than about 25 degrees API by controlling average pressure and average temperature in the selected section such that the average pressure in the selected section is greater than the pressure (p) set forth in the following equation for an assessed average temperature (T) in the selected section:

p=e[−44000/T+67]

where p is measured in psia and T is measured in ° Kelvin.

546. The method of claim 545, wherein the API gravity of the produced mixture is controlled to be greater than about 30 degrees API, and wherein the equation is:

p=e[−31000/T+51].

547. The method of claim 545, wherein the API gravity of the produced mixture is controlled to be greater than about 35 degrees API, and wherein the equation is:

p=e[−22000/T+38].

548. The method of claim 545, wherein the one or more heat sources comprise at least two heat sources, and wherein superposition of heat from at least the two heat sources pyrolyzes at least some hydrocarbons within the selected section of the formation.

549. The method of claim 545, wherein controlling the average temperature comprises maintaining a temperature in the selected section within a pyrolysis temperature range.

550. The method of claim 545, wherein the one or more heat sources comprise electrical heaters.

551. The method of claim 545, wherein the one or more heat sources comprise surface burners.

552. The method of claim 545, wherein the one or more heat sources comprise flameless distributed combustors.

553. The method of claim 545, wherein the one or more heat sources comprise natural distributed combustors.

554. The method of claim 545, further comprising controlling a temperature within at least a majority of the selected section of the formation, wherein the pressure is controlled as a function of temperature, or the temperature is controlled as a function of pressure.

555. The method of claim 545, further comprising controlling the heat such that an average heating rate of the selected section is less than about 1° C. per day during pyrolysis.

556. The method of claim 545, wherein providing heat from the one or more heat sources to at least the portion of formation comprises:

heating a selected volume (V) of the oil shale formation from the one or more heat sources, wherein the formation has an average heat capacity (Cv), and wherein the heating pyrolyzes at least some hydrocarbons within the selected volume of the formation; and

wherein heating energy/day provided to the volume is equal to or less than Pwr, wherein Pwr is calculated by the equation:

Pwr=h*V*Cv*ρB

wherein Pwr is the heating energy/day, h is an average heating rate of the formation, ρB is formation bulk density, and wherein the heating rate is less than about 10° C./day.

558. The method of claim 545, wherein providing heat from the one or more heat sources comprises heating the selected section such that a thermal conductivity of at least a portion of the selected section is greater than about 0.5 W/(m° C.).

559. The method of claim 545, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 0.1% by weight to about 15% by weight of the condensable hydrocarbons are olefins.

560. The method of claim 545, wherein the produced mixture comprises non-condensable hydrocarbons, and wherein about 0.1% by weight to about 15% by weight of the non-condensable hydrocarbons are olefins.

561. The method of claim 545, wherein the produced mixture comprises non-condensable hydrocarbons, and wherein a molar ratio of ethene to ethane in the non-condensable hydrocarbons ranges from about 0.001 to about 0.15.

562. The method of claim 545, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is nitrogen.

563. The method of claim 545, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is oxygen.

564. The method of claim 545, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is sulfur.

565. The method of claim 545, wherein the produced mixture comprises condensable hydrocarbons, wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons comprise oxygen containing compounds, and wherein the oxygen containing compounds comprise phenols.

566. The method of claim 545, wherein the produced mixture comprises condensable hydrocarbons, and wherein greater than about 20% by weight of the condensable hydrocarbons are aromatic compounds.

567. The method of claim 545, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 5% by weight of the condensable hydrocarbons comprises multi-ring aromatics with more than two rings.

568. The method of claim 545, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 0.3% by weight of the condensable hydrocarbons are asphaltenes.

569. The method of claim 545, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons are cycloalkanes.

570. The method of claim 545, wherein the produced mixture comprises a non-condensable component, wherein the non-condensable component comprises hydrogen, wherein the hydrogen is greater than about 10% by volume of the non-condensable component, and wherein the hydrogen is less than about 80% by volume of the non-condensable component.

571. The method of claim 545, wherein the produced mixture comprises ammonia, and wherein greater than about 0.05% by weight of the produced mixture is ammonia.

572. The method of claim 545, wherein the produced mixture comprises ammonia, and wherein the ammonia is used to produce fertilizer.

573. The method of claim 545, further comprising controlling formation conditions to produce a mixture of condensable hydrocarbons and H2, wherein a partial pressure of H2 within the mixture is greater than about 0.5 bars.

574. The method of claim 545, wherein a partial pressure of H2 is measured when the mixture is at a production well.

575. The method of claim 545, further comprising altering a pressure within the formation to inhibit production of hydrocarbons from the formation having carbon numbers greater than about 25.

576. The method of claim 545, wherein controlling formation conditions comprises recirculating a portion of hydrogen from the mixture into the formation.

577. The method of claim 545, further comprising:

providing hydrogen (H2) to the heated section to hydrogenate hydrocarbons within the section; and

heating a portion of the section with heat from hydrogenation.

578. The method of claim 545, wherein the produced mixture comprises hydrogen and condensable hydrocarbons, the method further comprising hydrogenating a portion of the produced condensable hydrocarbons with at least a portion of the produced hydrogen.

579. The method of claim 545, wherein allowing the heat to transfer comprises increasing a permeability of a majority of the selected section to greater than about 100 millidarcy.

580. The method of claim 545, wherein allowing the heat to transfer comprises substantially uniformly increasing a permeability of a majority of the selected section.

581. The method of claim 545, wherein the heat is controlled to yield greater than about 60% by weight of condensable hydrocarbons, as measured by Fischer Assay.

582. The method of claim 545, wherein producing the mixture comprises producing the mixture in a production well, and wherein at least about 7 heat sources are disposed in the formation for each production well.

583. The method of claim 582, wherein at least about 20 heat sources are disposed in the formation for each production well.

584. The method of claim 545, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, and wherein the unit of heat sources comprises a triangular pattern.

585. The method of claim 545, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, wherein the unit of heat sources comprises a triangular pattern, and wherein a plurality of the units are repeated over an area of the formation to form a repetitive pattern of units.

586. A method of treating an oil shale formation in situ, comprising:

providing heat to at least a portion of an oil shale formation such that a temperature (T) in a substantial part of the heated portion exceeds 270° C. and hydrocarbons are pyrolyzed within the heated portion of the formation;

controlling a pressure (p) within at least a substantial part of the heated portion of the formation;

wherein pbar>e[(−A/T)+B−26744];

wherein p is the pressure in bars absolute and T is the temperature in degrees K, and A and B are parameters that are larger than 10 and are selected in relation to the characteristics and composition of the oil shale formation and on the required olefin content and carbon number of the pyrolyzed hydrocarbon fluids; and

producing pyrolyzed hydrocarbon fluids from the heated portion of the formation.

587. The method of claim 586, wherein A is greater than 14000 and B is greater than about 25 and a majority of the produced pyrolyzed hydrocarbon fluids have an average carbon number lower than 25 and comprise less than about 10% by weight of olefins.

588. The method of claim 586, wherein T is less than about 390° C., p is greater than about 1.4 bars, A is greater than about 44000, and b is greater than about 67, and a majority of the produced pyrolyzed hydrocarbon fluids have an average carbon number less than 25 and comprise less than 10% by weight of olefins.

589. The method of claim 586, wherein T is less than about 390° C., p is greater than about 2 bars, A is less than about 57000, and b is less than about 83, and a majority of the produced pyrolyzed hydrocarbon fluids have an average carbon number lower than about 21.

590. The method of claim 586, further comprising controlling the heat such that an average heating rate of the heated portion is less than about 3° C. per day during pyrolysis.

591. The method of claim 586, wherein providing heat from the one or more heat sources to at least the portion of formation comprises:

heating a selected volume (V) of the oil shale formation from the one or more heat sources, wherein the formation has an average heat capacity (Cv), and wherein the heating pyrolyzes at least some hydrocarbons within the selected volume of the formation; and

wherein heating energy/day provided to the volume is equal to or less than Pwr, wherein Pwr is calculated by the equation:

Pwr=h*V*Cv*ρB

wherein Pwr is the heating energy/day, h is an average heating rate of the formation, ρB is formation bulk density, and wherein the heating rate is less than about 10° C./day.

592. The method of claim 586, wherein heat is transferred substantially by conduction from the one or more heat sources to the heated portion of the formation.

593. The method of claim 586, wherein heat is transferred substantially by conduction from the one or more heat sources to the heated portion of the formation such that the thermal conductivity of at least part of the heated portion is substantially uniformly modified to a value greater than about 0.6 W/m° C. and the permeability of said part increases substantially uniformly to a value greater than 1 Darcy.

594. The method of claim 586, further comprising controlling formation conditions to produce a mixture of hydrocarbon fluids and H2, wherein a partial pressure of H2 within the mixture flowing through the formation is greater than 0.5 bars.

595. The method of claim 594, further comprising, hydrogenating a portion of the produced pyrolyzed hydrocarbon fluids with at least a portion of the produced hydrogen and heating the fluids with heat from hydrogenation.

596. The method of claim 586, wherein the substantially gaseous pyrolyzed hydrocarbon fluids are produced from a production well, the method further comprising heating a wellbore of the production well to inhibit condensation of the hydrocarbon fluids within the wellbore.

597. A method of treating an oil shale formation in situ, comprising:

providing heat from one or more heat sources to at least a portion of the formation;

allowing the heat to transfer from the one or more heat sources to a selected section of the formation to raise an average temperature within the selected section to, or above, a temperature that will pyrolyze hydrocarbons within the selected section;

producing a mixture from the formation; and

controlling a weight percentage of olefins of the produced mixture to be less than about 20% by weight by controlling average pressure and average temperature in the selected section such that the average pressure in the selected section is greater than the pressure (p) set forth in the following equation for an assessed average temperature (T) in the selected section:

p=e[−57000/T+83]

where p is measured in psia and T is measured in ° Kelvin.

598. The method of claim 597, wherein the weight percentage of olefins of the produced mixture is controlled to be less than about 10% by weight, and wherein the equation is:

p=e[−16000/T+28].

599. The method of claim 597, wherein the weight percentage of olefins of the produced mixture is controlled to be less than about 5% by weight, and wherein the equation is:

p=e[−12000/T+22].

600. The method of claim 597, wherein the one or more heat sources comprise at least two heat sources, and wherein superposition of heat from at least the two heat sources pyrolyzes at least some hydrocarbons within the selected section of the formation.

601. The method of claim 597, wherein the one or more heat sources comprise electrical heaters.

602. The method of claim 597, wherein the one or more heat sources comprise surface burners.

603. The method of claim 597, wherein the one or more heat sources comprise flameless distributed combustors.

604. The method of claim 597, wherein the one or more heat sources comprise natural distributed combustors.

605. The method of claim 597, further comprising controlling a temperature within at least a majority of the selected section of the formation, wherein the pressure is controlled as a function of temperature, or the temperature is controlled as a function of pressure.

606. The method of claim 605, wherein controlling an average temperature comprises maintaining a temperature within the selected section within a pyrolysis temperature range.

607. The method of claim 597, further comprising controlling the heat such that an average heating rate of the selected section is less than about 3.0° C. per day during pyrolysis.

608. The method of claim 597, further comprising controlling the heat such that an average heating rate of the selected section is less than about 1° C. per day during pyrolysis.

609. The method of claim 597, wherein providing heat from the one or more heat sources to at least the portion of formation comprises:

heating a selected volume (V) of the oil shale formation from the one or more heat sources, wherein the formation has an average heat capacity (Cv), and wherein the heating pyrolyzes at least some hydrocarbons within the selected volume of the formation; and

wherein heating energy/day provided to the volume is equal to or less than Pwr, wherein Pwr is calculated by the equation:

Pwr=h*V*Cv*ρB

wherein Pwr is the heating energy/day, h is an average heating rate of the formation, ρB is formation bulk density, and wherein the heating rate is less than about 10° C./day.

611. The method of claim 597, wherein providing heat from the one or more heat sources comprises heating the selected formation such that a thermal conductivity of at least a portion of the selected section is greater than about 0.5 W/(m° C.).

612. The method of claim 597, wherein the produced mixture comprises condensable hydrocarbons having an API gravity of at least about 25°.

613. The method of claim 597, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 0.1% by weight to about 15% by weight of the condensable hydrocarbons are olefins.

614. The method of claim 597, wherein the produced mixture comprises non-condensable hydrocarbons, and wherein about 0.1% by weight to about 15% by weight of the non-condensable hydrocarbons are olefins.

615. The method of claim 597, wherein the produced mixture comprises non-condensable hydrocarbons, and wherein a molar ratio of ethene to ethane in the non-condensable hydrocarbons ranges from about 0.001 to about 0.15.

616. The method of claim 597, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is nitrogen.

617. The method of claim 597, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is oxygen.

618. The method of claim 597, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is sulfur.

619. The method of claim 597, wherein the produced mixture comprises condensable hydrocarbons, wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons comprise oxygen containing compounds, and wherein the oxygen containing compounds comprise phenols.

620. The method of claim 597, wherein the produced mixture comprises condensable hydrocarbons, and wherein greater than about 20% by weight of the condensable hydrocarbons are aromatic compounds.

621. The method of claim 597, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 5% by weight of the condensable hydrocarbons comprises multi-ring aromatics with more than two rings.

622. The method of claim 597, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 0.3% by weight of the condensable hydrocarbons are asphaltenes.

623. The method of claim 597, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons are cycloalkanes.

624. The method of claim 597, wherein the produced mixture comprises a non-condensable component, wherein the non-condensable component comprises hydrogen, wherein the hydrogen is greater than about 10% by volume of the non-condensable component, and wherein the hydrogen is less than about 80% by volume of the non-condensable component.

625. The method of claim 597, wherein the produced mixture comprises ammonia, and wherein greater than about 0.05% by weight of the produced mixture is ammonia.

626. The method of claim 597, wherein the produced mixture comprises ammonia, and wherein the ammonia is used to produce fertilizer.

627. The method of claim 597, further comprising controlling formation conditions to produce a mixture of condensable hydrocarbons and H2, wherein a partial pressure of H2 within the mixture is greater than about 0.5 bars.

628. The method of claim 597, wherein a partial pressure of H2 is measured when the mixture is at a production well.

629. The method of claim 597, further comprising altering a pressure within the formation to inhibit production of hydrocarbons from the formation having carbon numbers greater than about 25.

630. The method of claim 597, wherein controlling formation conditions comprises recirculating a portion of hydrogen from the mixture into the formation.

631. The method of claim 597, further comprising:

providing hydrogen (H2) to the heated section to hydrogenate hydrocarbons within the section; and

heating a portion of the section with heat from hydrogenation.

632. The method of claim 597, wherein the produced mixture comprises hydrogen and condensable hydrocarbons, the method further comprising hydrogenating a portion of the produced condensable hydrocarbons with at least a portion of the produced hydrogen.

633. The method of claim 597, wherein allowing the heat to transfer comprises increasing a permeability of a majority of the selected section to greater than about 100 millidarcy.

634. The method of claim 597, wherein allowing the heat to transfer comprises substantially uniformly increasing a permeability of a majority of the selected section.

635. The method of claim 597, further comprising controlling the heat to yield greater than about 60% by weight of condensable hydrocarbons, as measured by Fischer Assay.

636. The method of claim 597, wherein producing the mixture comprises producing the mixture in a production well, and wherein at least about 7 heat sources are disposed in the formation for each production well.

637. The method of claim 636, wherein at least about 20 heat sources are disposed in the formation for each production well.

638. The method of claim 597, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, and wherein the unit of heat sources comprises a triangular pattern.

639. The method of claim 597, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, wherein the unit of heat sources comprises a triangular pattern, and wherein a plurality of the units are repeated over an area of the formation to form a repetitive pattern of units.

640. A method of treating an oil shale formation in situ, comprising:

providing heat from one or more heat sources to at least a portion of the formation;

allowing the heat to transfer from the one or more heat sources to a selected section of the formation to raise an average temperature within the selected section to, or above, a temperature that will pyrolyze hydrocarbons within the selected section;

producing a mixture from the formation; and

controlling hydrocarbons having carbon numbers greater than 25 of the produced mixture to be less than about 25% by weight by controlling average pressure and average temperature in the selected section such that the average pressure in the selected section is greater than the pressure (p) set forth in the following equation for an assessed average temperature (T) in the selected section:

p=e[−14000/T+25]

where p is measured in psia and T is measured in ° Kelvin.

641. The method of claim 640, wherein the hydrocarbons having carbon numbers greater than 25 of the produced mixture is controlled to be less than about 20% by weight, and wherein the equation is:

p=e[−16000/T+28].

642. The method of claim 640, wherein the hydrocarbons having carbon numbers greater than 25 of the produced mixture is controlled to be less than about 15% by weight, and wherein the equation is:

p=e[−18000/T+32].

643. The method of claim 640, wherein the one or more heat sources comprise at least two heat sources, and wherein superposition of heat from at least the two heat sources pyrolyzes at least some hydrocarbons within the selected section of the formation.

644. The method of claim 640, wherein the one or more heat sources comprise electrical heaters.

645. The method of claim 640, wherein the one or more heat sources comprise surface burners.

646. The method of claim 640, wherein the one or more heat sources comprise flameless distributed combustors.

647. The method of claim 640, wherein the one or more heat sources comprise natural distributed combustors.

648. The method of claim 640, further comprising controlling a temperature within at least a majority of the selected section of the formation, wherein the pressure is controlled as a function of temperature, or the temperature is controlled as a function of pressure.

649. The method of claim 648, wherein controlling the temperature comprises maintaining a temperature within the selected section within a pyrolysis temperature range.

650. The method of claim 640, further comprising controlling the heat such that an average heating rate of the selected section is less than about 1° C. per day during pyrolysis.

651. The method of claim 640, wherein providing heat from the one or more heat sources to at least the portion of formation comprises:

heating a selected volume (V) of the oil shale formation from the one or more heat sources, wherein the formation has an average heat capacity (Cv), and wherein the heating pyrolyzes at least some hydrocarbons within the selected volume of the formation; and

wherein heating energy/day provided to the volume is equal to or less than Pwr, wherein Pwr is calculated by the equation:

Pwr=h*V*Cv*ρB

wherein Pwr is the heating energy/day, h is an average heating rate of the formation, ρB is formation bulk density, and wherein the heating rate is less than about 10° C./day.

653. The method of claim 640, wherein providing heat from the one or more heat sources comprises heating the selected section such that a thermal conductivity of at least a portion of the selected section is greater than about 0.5 W/(m° C.).

654. The method of claim 640, wherein the produced mixture comprises condensable hydrocarbons having an API gravity of at least about 25°.

655. The method of claim 640, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 0.1% by weight to about 15% by weight of the condensable hydrocarbons are olefins.

656. The method of claim 640, wherein the produced mixture comprises non-condensable hydrocarbons, and wherein a molar ratio of ethene to ethane in the non-condensable hydrocarbons ranges from about 0.001 to about 0.15.

657. The method of claim 640, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is nitrogen.

658. The method of claim 640, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is oxygen.

659. The method of claim 640, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is sulfur.

660. The method of claim 640, wherein the produced mixture comprises condensable hydrocarbons, wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons comprise oxygen containing compounds, and wherein the oxygen containing compounds comprise phenols.

661. The method of claim 640, wherein the produced mixture comprises condensable hydrocarbons, and wherein greater than about 20% by weight of the condensable hydrocarbons are aromatic compounds.

662. The method of claim 640, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 5% by weight of the condensable hydrocarbons comprises multi-ring aromatics with more than two rings.

663. The method of claim 640, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 0.3% by weight of the condensable hydrocarbons are asphaltenes.

664. The method of claim 640, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 5% by weight to about 0.3% by weight of the condensable hydrocarbons are cycloalkanes.

665. The method of claim 640, wherein the produced mixture comprises a non-condensable component, wherein the non-condensable component comprises hydrogen, wherein the hydrogen is greater than about 10% by volume of the non-condensable component, and wherein the hydrogen is less than about 80% by volume of the non-condensable component.

666. The method of claim 640, wherein the produced mixture comprises ammonia, and wherein greater than about 0.05% by weight of the produced mixture is ammonia.

667. The method of claim 640, wherein the produced mixture comprises ammonia, and wherein the ammonia is used to produce fertilizer.

668. The method of claim 640, further comprising controlling formation conditions to produce a mixture of condensable hydrocarbons and H2, wherein a partial pressure of H2 within the mixture is greater than about 0.5 bars.

669. The method of claim 640, wherein a partial pressure of H2 is measured when the mixture is at a production well.

670. The method of claim 640, further comprising altering a pressure within the formation to inhibit production of hydrocarbons from the formation having carbon numbers greater than about 25.

671. The method of claim 640, further comprising:

providing hydrogen (H2) to the heated section to hydrogenate hydrocarbons within the section; and

heating a portion of the section with heat from hydrogenation.

672. The method of claim 640, wherein the produced mixture comprises hydrogen and condensable hydrocarbons, the method further comprising hydrogenating a portion of the produced condensable hydrocarbons with at least a portion of the produced hydrogen.

673. The method of claim 640, wherein allowing the heat to transfer comprises increasing a permeability of a majority of the selected section to greater than about 100 millidarcy.

674. The method of claim 640, wherein allowing the heat to transfer comprises substantially uniformly increasing a permeability of a majority of the selected section.

675. The method of claim 640, further comprising controlling the heat to yield greater than about 60% by weight of condensable hydrocarbons, as measured by Fischer Assay.

676. The method of claim 640, wherein producing the mixture comprises producing the mixture in a production well, and wherein at least about 7 heat sources are disposed in the formation for each production well.

677. The method of claim 676, wherein at least about 20 heat sources are disposed in the formation for each production well.

678. The method of claim 640, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, and wherein the unit of heat sources comprises a triangular pattern.

679. The method of claim 640, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, wherein the unit of heat sources comprises a triangular pattern, and wherein a plurality of the units are repeated over an area of the formation to form a repetitive pattern of units.

680. A method of treating an oil shale formation in situ, comprising:

providing heat from one or more heat sources to at least a portion of the formation;

allowing the heat to transfer from the one or more heat sources to a selected section of the formation to raise an average temperature within the selected section to, or above, a temperature that will pyrolyze hydrocarbons within the selected section;

producing a mixture from the formation; and

controlling an atomic hydrogen to carbon ratio of the produced mixture to be greater than about 1.7 by controlling average pressure and average temperature in the selected section such that the average pressure in the selected section is greater than the pressure (p) set forth in the following equation for an assessed average temperature (T) in the selected section:

p=e[−38000/T+61]

where p is measured in psia and T is measured in ° Kelvin.

681. The method of claim 680, wherein the atomic hydrogen to carbon ratio of the produced mixture is controlled to be greater than about 1.8, and wherein the equation is:

p=e[−13000/T+24].

682. The method of claim 680, wherein the atomic hydrogen to carbon ratio of the produced mixture is controlled to be greater than about 1.9, and wherein the equation is:

p=e[−8000/T+18].

683. The method of claim 680, wherein the one or more heat sources comprise at least two heat sources, and wherein superposition of heat from at least the two heat sources pyrolyzes at least some hydrocarbons within the selected section of the formation.

684. The method of claim 680, wherein the one or more heat sources comprise electrical heaters.

685. The method of claim 680, wherein the one or more heat sources comprise surface burners.

686. The method of claim 680, wherein the one or more heat sources comprise flameless distributed combustors.

687. The method of claim 680, wherein the one or more heat sources comprise natural distributed combustors.

688. The method of claim 680, further comprising controlling a temperature within at least a majority of the selected section of the formation, wherein the pressure is controlled as a function of temperature, or the temperature is controlled as a function of pressure.

689. The method of claim 688, wherein controlling the temperature comprises maintaining a temperature within the selected section within a pyrolysis temperature range.

690. The method of claim 680, further comprising controlling the heat such that an average heating rate of the selected section is less than about 1° C. per day during pyrolysis.

691. The method of claim 680, wherein providing heat from the one or more heat sources to at least the portion of formation comprises:

heating a selected volume (V) of the oil shale formation from the one or more heat sources, wherein the formation has an average heat capacity (Cv), and wherein the heating pyrolyzes at least some hydrocarbons within the selected volume of the formation; and

wherein heating energy/day provided to the volume is equal to or less than Pwr, wherein Pwr is calculated by the equation:

Pwr=h*Y*Cv*ρB

wherein Pwr is the heating energy/day, h is an average heating rate of the formation, ρB is formation bulk density, and wherein the heating rate is less than about 10° C./day.

693. The method of claim 680, wherein providing heat from the one or more heat sources comprises heating the selected section such that a thermal conductivity of at least a portion of the selected section is greater than about 0.5 W/(m° C.).

694. The method of claim 680, wherein the produced mixture comprises condensable hydrocarbons having an API gravity of at least about 25°.

695. The method of claim 680, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 0.1% by weight to about 15% by weight of the condensable hydrocarbons are olefins.

696. The method of claim 680, wherein the produced mixture comprises non-condensable hydrocarbons, and wherein about 0.1% by weight to about 15% by weight of the non-condensable hydrocarbons are olefins.

697. The method of claim 680, wherein the produced mixture comprises non-condensable hydrocarbons, and wherein a molar ratio of ethene to ethane in the non-condensable hydrocarbons ranges from about 0.001 to about 0.15.

698. The method of claim 680, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is nitrogen.

699. The method of claim 680, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is oxygen.

700. The method of claim 680, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is sulfur.

701. The method of claim 680, wherein the produced mixture comprises condensable hydrocarbons, wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons comprise oxygen containing compounds, and wherein the oxygen containing compounds comprise phenols.

702. The method of claim 680, wherein the produced mixture comprises condensable hydrocarbons, and wherein greater than about 20% by weight of the condensable hydrocarbons are aromatic compounds.

703. The method of claim 680, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 5% by weight of the condensable hydrocarbons comprises multi-ring aromatics with more than two rings.

704. The method of claim 680, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 0.3% by weight of the condensable hydrocarbons are asphaltenes.

705. The method of claim 680, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons are cycloalkanes.

706. The method of claim 680, wherein the produced mixture comprises a non-condensable component, wherein the non-condensable component comprises hydrogen, wherein the hydrogen is greater than about 10% by volume of the non-condensable component, and wherein the hydrogen is less than about 80% by volume of the non-condensable component.

707. The method of claim 680, wherein the produced mixture comprises ammonia, and wherein greater than about 0.05% by weight of the produced mixture is ammonia.

708. The method of claim 680, wherein the produced mixture comprises ammonia, and wherein the ammonia is used to produce fertilizer.

709. The method of claim 680, further comprising controlling formation conditions to produce a mixture of condensable hydrocarbons and H2, wherein a partial pressure of H2 within the mixture is greater than about 0.5 bars.

710. The method of claim 680, wherein a partial pressure of H2 is measured when the mixture is at a production well.

711. The method of claim 680, further comprising altering a pressure within the formation to inhibit production of hydrocarbons from the formation having carbon numbers greater than about 25.

712. The method of claim 680, wherein controlling formation conditions comprises recirculating a portion of hydrogen from the mixture into the formation.

713. The method of claim 680, further comprising:

providing hydrogen (H2) to the heated section to hydrogenate hydrocarbons within the section; and

heating a portion of the section with heat from hydrogenation.

714. The method of claim 680, wherein the produced mixture comprises hydrogen and condensable hydrocarbons, the method further comprising hydrogenating a portion of the produced condensable hydrocarbons with at least a portion of the produced hydrogen.

715. The method of claim 680, wherein allowing the heat to transfer comprises increasing a permeability of a majority of the selected section to greater than about 100 millidarcy.

716. The method of claim 680, wherein allowing the heat to transfer comprises substantially uniformly increasing a permeability of a majority of the selected section.

717. The method of claim 680, further comprising controlling the heat to yield greater than about 60% by weight of condensable hydrocarbons, as measured by Fischer Assay.

718. The method of claim 680, wherein producing the mixture comprises producing the mixture in a production well, and wherein at least about 7 heat sources are disposed in the formation for each production well.

719. The method of claim 718, wherein at least about 20 heat sources are disposed in the formation for each production well.

720. The method of claim 680, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, and wherein the unit of heat sources comprises a triangular pattern.

721. The method of claim 680, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, wherein the unit of heat sources comprises a triangular pattern, and wherein a plurality of the units are repeated over an area of the formation to form a repetitive pattern of units.

722. A method of treating an oil shale formation in situ, comprising:

providing heat from one or more heat sources to at least one portion of the formation;

allowing the heat to transfer from the one or more heat sources to a selected section of the formation;

controlling a pressure-temperature relationship within at least the selected section of the formation by selected energy input into the one or more heat sources and by pressure release from the selected section through wellbores of the one or more heat sources; and

producing a mixture from the formation.

723. The method of claim 722, wherein the one or more heat sources comprise at least two heat sources, and wherein superposition of heat from at least the two heat sources pyrolyzes at least some hydrocarbons within the selected section of the formation.

724. The method of claim 722, wherein the one or more heat sources comprise at least two heat sources.

725. The method of claim 722, wherein the one or more heat sources comprise surface burners.

726. The method of claim 722, wherein the one or more heat sources comprise flameless distributed combustors.

727. The method of claim 722, wherein the one or more heat sources comprise natural distributed combustors.

728. The method of claim 722, further comprising controlling the pressure-temperature relationship by controlling a rate of removal of fluid from the formation.

729. The method of claim 722, further comprising controlling the heat such that an average heating rate of the selected section is less than about 1° C. per day during pyrolysis.

730. The method of claim 722, wherein providing heat from the one or more heat sources to at least the portion of formation comprises:

heating a selected volume (V) of the oil shale formation from the one or more heat sources, wherein the formation has an average heat capacity (Cv), and wherein the heating pyrolyzes at least some hydrocarbons within the selected volume of the formation; and

wherein heating energy/day provided to the volume is equal to or less than Pwr, wherein Pwr is calculated by the equation:

Pwr=h*V*Cv*ρB

wherein Pwr is the heating energy/day, h is an average heating rate of the formation, ρB is formation bulk density, and wherein the heating rate is less than about 10° C./day.

732. The method of claim 722, wherein providing heat from the one or more heat sources comprises heating the selected section such that a thermal conductivity of at least a portion of the selected section is greater than about 0.5 W/(m° C.).

733. The method of claim 722, wherein the produced mixture comprises condensable hydrocarbons having an API gravity of at least about 25°.

734. The method of claim 722, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 0.1% by weight to about 15% by weight of the condensable hydrocarbons are olefins.

735. The method of claim 722, wherein the produced mixture comprises non-condensable hydrocarbons, and wherein about 0.1% by weight to about 15% by weight of the non-condensable hydrocarbons are olefins.

736. The method of claim 722, wherein the produced mixture comprises non-condensable hydrocarbons, and wherein a molar ratio of ethene to ethane in the non-condensable hydrocarbons ranges from about 0.001 to about 0.15.

737. The method of claim 722, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is nitrogen.

738. The method of claim 722, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is oxygen.

739. The method of claim 722, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is sulfur.

740. The method of claim 722, wherein the produced mixture comprises condensable hydrocarbons, wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons comprise oxygen containing compounds, and wherein the oxygen containing compounds comprise phenols.

741. The method of claim 722, wherein the produced mixture comprises condensable hydrocarbons, and wherein greater than about 20% by weight of the condensable hydrocarbons are aromatic compounds.

742. The method of claim 722, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 5% by weight of the condensable hydrocarbons comprises multi-ring aromatics with more than two rings.

743. The method of claim 722, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 0.3% by weight of the condensable hydrocarbons are asphaltenes.

744. The method of claim 722, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons are cycloalkanes.

745. The method of claim 722, wherein the produced mixture comprises a non-condensable component, wherein the non-condensable component comprises hydrogen, wherein the hydrogen is greater than about 10% by volume of the non-condensable component, and wherein the hydrogen is less than about 80% by volume of the non-condensable component.

746. The method of claim 722, wherein the produced mixture comprises ammonia, and wherein greater than about 0.05% by weight of the produced mixture is ammonia.

747. The method of claim 722, wherein the produced mixture comprises ammonia, and wherein the ammonia is used to produce fertilizer.

748. The method of claim 722, further comprising controlling a pressure within at least a majority of the selected section of the formation, wherein the controlled pressure is at least about 2.0 bars absolute.

749. The method of claim 722, further comprising controlling formation conditions to produce a mixture of hydrocarbon fluids and H2, wherein a partial pressure of H2 within the mixture is greater than about 0.5 bars.

750. The method of claim 722, further comprising controlling formation conditions to produce a mixture of condensable hydrocarbons and H2, wherein a partial pressure of H2 within the mixture is greater than about 0.5 bars.

751. The method of claim 722, wherein a partial pressure of H2 is measured when the mixture is at a production well.

752. The method of claim 722, further comprising altering a pressure within the formation to inhibit production of hydrocarbons from the formation having carbon numbers greater than about 25.

753. The method of claim 722, wherein controlling formation conditions comprises recirculating a portion of hydrogen from the mixture into the formation.

754. The method of claim 722, further comprising:

providing hydrogen (H2) to the heated section to hydrogenate hydrocarbons within the section; and

heating a portion of the section with heat from hydrogenation.

755. The method of claim 722, wherein the produced mixture comprises hydrogen and condensable hydrocarbons, the method further comprising hydrogenating a portion of the produced condensable hydrocarbons with at least a portion of the produced hydrogen.

756. The method of claim 722, wherein allowing the heat to transfer comprises increasing a permeability of a majority of the selected section to greater than about 100 millidarcy.

757. The method of claim 722, wherein allowing the heat to transfer comprises substantially uniformly increasing a permeability of a majority of the selected section.

758. The method of claim 722, further comprising controlling the heat to yield greater than about 60% by weight of condensable hydrocarbons, as measured by Fischer Assay.

759. The method of claim 722, wherein producing the mixture comprises producing the mixture in a production well, and wherein at least about 7 heat sources are disposed in the formation for each production well.

760. The method of claim 759, wherein at least about 20 heat sources are disposed in the formation for each production well.

761. The method of claim 722, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, and wherein the unit of heat sources comprises a triangular pattern.

762. The method of claim 722, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, wherein the unit of heat sources comprises a triangular pattern, and wherein a plurality of the units are repeated over an area of the formation to form a repetitive pattern of units.

763. A method of treating an oil shale formation in situ, comprising:

heating a selected volume (V) of the oil shale formation, wherein formation has an average heat capacity (Cv), and wherein the heating pyrolyzes at least some hydrocarbons within the selected volume of the formation; and

wherein heating energy/day provided to the volume is equal to or less than Pwr, wherein Pwr is calculated by the equation:

Pwr=h*V*Cv*ρB

wherein Pwr is the heating energy/day, h is an average heating rate of the formation, ρB is formation bulk density, and wherein the heating rate is less than about 10° C./day.

767. The method of claim 763, wherein heating a selected volume comprises heating with at least one natural distributed combustor.

768. The method of claim 763, further comprising controlling a pressure and a temperature within at least a majority of the selected volume of the formation, wherein the pressure is controlled as a function of temperature, or the temperature is controlled as a function of pressure.

769. The method of claim 763, further comprising controlling the heating such that an average heating rate of the selected volume is less than about 1° C. per day during pyrolysis.

770. The method of claim 763, wherein a value for Cv is determined as an average heat capacity of two or more samples taken from the oil shale formation.

772. The method of claim 763, wherein heating the selected volume comprises heating the selected section such that a thermal conductivity of at least a portion of the selected section is greater than about 0.5 W/(m° C.).

773. The method of claim 763, wherein the produced mixture comprises condensable hydrocarbons having an API gravity of at least about 25°.

774. The method of claim 763, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 0.1% by weight to about 15% by weight of the condensable hydrocarbons are olefins.

775. The method of claim 763, wherein the produced mixture comprises non-condensable hydrocarbons, and wherein about 0.1% by weight to about 15% by weight of the non-condensable hydrocarbons are olefins.

776. The method of claim 763, wherein the produced mixture comprises non-condensable hydrocarbons, and wherein a molar ratio of ethene to ethane in the non-condensable hydrocarbons ranges from about 0.001 to about 0.15.

777. The method of claim 763, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is nitrogen.

778. The method of claim 763, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is oxygen.

779. The method of claim 763, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is sulfur.

780. The method of claim 763, wherein the produced mixture comprises condensable hydrocarbons, wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons comprise oxygen containing compounds, and wherein the oxygen containing compounds comprise phenols.

781. The method of claim 763, wherein the produced mixture comprises condensable hydrocarbons, and wherein greater than about 20% by weight of the condensable hydrocarbons are aromatic compounds.

782. The method of claim 763, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 5% by weight of the condensable hydrocarbons comprises multi-ring aromatics with more than two rings.

783. The method of claim 763, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 0.3% by weight of the condensable hydrocarbons are asphaltenes.

784. The method of claim 763, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons are cycloalkanes.

785. The method of claim 763, wherein the produced mixture comprises a non-condensable component, wherein the non-condensable component comprises hydrogen, wherein the hydrogen is greater than about 10% by volume of the non-condensable component, and wherein the hydrogen is less than about 80% by volume of the non-condensable component.

786. The method of claim 763, wherein the produced mixture comprises ammonia, and wherein greater than about 0.05% by weight of the produced mixture is ammonia.

787. The method of claim 763, wherein the produced mixture comprises ammonia, and wherein the ammonia is used to produce fertilizer

788. The method of claim 763, further comprising controlling a pressure within at least a majority of the selected volume of the formation, wherein the controlled pressure is at least about 2.0 bars absolute.

789. The method of claim 763, further comprising controlling formation conditions to produce a mixture from the formation comprising condensable hydrocarbons and H2, wherein a partial pressure of H2 within the mixture is greater than about 0.5 bars.

790. The method of claim 763, wherein a partial pressure of H2 is measured when the mixture is at a production well.

791. The method of claim 763, further comprising altering a pressure within the formation to inhibit production of hydrocarbons from the formation having carbon numbers greater than about 25.

792. The method of claim 763, wherein controlling formation conditions comprises recirculating a portion of hydrogen from the mixture into the formation.

793. The method of claim 763, further comprising:

providing hydrogen (H2) to the heated volume to hydrogenate hydrocarbons within the volume; and

heating a portion of the volume with heat from hydrogenation.

794. The method of claim 763, wherein the produced mixture comprises hydrogen and condensable hydrocarbons, the method further comprising hydrogenating a portion of the produced condensable hydrocarbons with at least a portion of the produced hydrogen.

795. The method of claim 763, further comprising increasing a permeability of a majority of the selected volume to greater than about 100 millidarcy.

796. The method of claim 763, further comprising substantially uniformly increasing a permeability of a majority of the selected volume.

797. The method of claim 763, further comprising controlling the heat to yield greater than about 60% by weight of condensable hydrocarbons, as measured by Fischer Assay.

798. The method of claim 763, wherein producing the mixture comprises producing the mixture in a production well, and wherein at least about 7 heat sources are disposed in the formation for each production well.

799. The method of claim 798, wherein at least about 20 heat sources are disposed in the formation for each production well.

800. The method of claim 763, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, and wherein the unit of heat sources comprises a triangular pattern.

801. The method of claim 763, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, wherein the unit of heat sources comprises a triangular pattern, and wherein a plurality of the units are repeated over an area of the formation to form a repetitive pattern of units.

802. A method of treating an oil shale formation in situ, comprising:

providing heat from one or more heat sources to at least a portion of the formation;

allowing the heat to transfer from the one or more heat sources to a selected section of the formation to raise an average temperature within the selected section to, or above, a temperature that will pyrolyze hydrocarbons within the selected section;

controlling heat output from the one or more heat sources such that an average heating rate of the selected section rises by less than about 3° C. per day when the average temperature of the selected section is at, or above, the temperature that will pyrolyze hydrocarbons within the selected section; and

raising the average temperature within the selected section to a first temperature that is at or above a minimum pyrolysis temperature of hydrocarbons within the formation;

limiting energy input into the one or more heat sources to inhibit increase in temperature of the selected section; and

increasing energy input into the formation to raise an average temperature of the selected section above the first temperature when production of formation fluid declines below a desired production rate.

raising the average temperature within the selected section to a first temperature that is at or above a minimum pyrolysis temperature of hydrocarbons within the formation;

limiting energy input into the one or more heat sources to inhibit increase in temperature of the selected section; and

increasing energy input into the formation to raise an average temperature of the selected section above the first temperature when quality of formation fluid produced from the formation falls below a desired quality.

805. The method of claim 802, wherein the one or more heat sources comprise at least two heat sources, and wherein superposition of heat from at least the two heat sources pyrolyzes at least some hydrocarbons within the selected section.

806. The method of claim 802, wherein the one or more heat sources comprise electrical heaters.

807. The method of claim 802, wherein the one or more heat sources comprise surface burners.

808. The method of claim 802, wherein the one or more heat sources comprise flameless distributed combustors.

809. The method of claim 802, wherein the one or more heat sources comprise natural distributed combustors.

810. The method of claim 802, further comprising controlling a pressure and a temperature within at least a majority of the selected section of the formation, wherein the pressure is controlled as a function of temperature, or the temperature is controlled as a function of pressure.

811. The method of claim 802, wherein the heat is controlled such that an average heating rate of the selected section is less than about 1.5° C. per day during pyrolysis.

812. The method of claim 802, wherein the heat is controlled such that an average heating rate of the selected section is less than about 1° C. per day during pyrolysis.

813. The method of claim 802, wherein providing heat from the one or more heat sources to at least the portion of formation comprises:

heating a selected volume (V) of the oil shale formation from the one or more heat sources, wherein the formation has an average heat capacity (Cv), and wherein the heating pyrolyzes at least some hydrocarbons within the selected volume of the formation; and

wherein heat ing energy/day provided to the volume is equal to or less than Pwr, wherein Pwr is calculated by the equation:

Pwr=h*V*Cv*ρB

wherein Pwr is the heating energy/day, h is an average heating rate of the formation, ρB is formation bulk density.

815. The method of claim 802, wherein providing heat from the one or more heat sources comprises heating the selected section such that a thermal conductivity of at least a portion of the selected section is greater than about 0.5 W/(m° C.).

816. The method of claim 802, wherein the produced mixture comprises condensable hydrocarbons having an API gravity of at least about 25°.

817. The method of claim 802, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 0.1% by weight to about 15% by weight of the condensable hydrocarbons are olefins.

818. The method of claim 802, wherein the produced mixture comprises condensable hydrocarbons, wherein the condensable hydrocarbons have an olefin content is less than about 2.5% by weight of the condensable hydrocarbons, and wherein the olefin content is greater than about 0.1% by weight of the condensable hydrocarbons.

819. The method of claim 802, wherein the produced mixture comprises non-condensable hydrocarbons, wherein a molar ratio of ethene to ethane in the non-condensable hydrocarbons is less than about 0.15, and wherein the ratio of ethene to ethane is greater than about 0.001.

820. The method of claim 802, wherein the produced mixture comprises non-condensable hydrocarbons, and wherein a molar ratio of ethene to ethane in the non-condensable hydrocarbons is less than about 0.10 and wherein the ratio of ethene to ethane is greater than about 0.001.

821. The method of claim 802, wherein the produced mixture comprises non-condensable hydrocarbons, and wherein a molar ratio of ethene to ethane in the non-condensable hydrocarbons is less than about 0.05 and wherein the ratio of ethene to ethane is greater than about 0.001.

822. The method of claim 802, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is nitrogen.

823. The method of claim 802, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is oxygen.

824. The method of claim 802, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is sulfur.

825. The method of claim 802, wherein the produced mixture comprises condensable hydrocarbons, wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons comprise oxygen containing compounds, and wherein the oxygen containing compounds comprise phenols.

826. The method of claim 802, wherein the produced mixture comprises condensable hydrocarbons, and wherein greater than about 20% by weight of the condensable hydrocarbons are aromatic compounds.

827. The method of claim 802, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 5% by weight of the condensable hydrocarbons comprises multi-ring aromatics with more than two rings.

828. The method of claim 802, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 0.3% by weight of the condensable hydrocarbons are asphaltenes.

829. The method of claim 802, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons are cycloalkanes.

830. The method of claim 802, wherein the produced mixture comprises a non-condensable component, wherein the non-condensable component comprises hydrogen, wherein the hydrogen is greater than about 10% by volume of the non-condensable component, and wherein the hydrogen is less than about 80% by volume of the non-condensable component.

831. The method of claim 802, wherein the produced mixture comprises ammonia, and wherein greater than about 0.05% by weight of the produced mixture is ammonia.

832. The method of claim 802, wherein the produced mixture comprises ammonia, and wherein the ammonia is used to produce fertilizer.

833. The method of claim 802, further comprising controlling a pressure within at least a majority of the selected section of the formation, wherein the controlled pressure is at least about 2.0 bars absolute.

834. The method of claim 802, further comprising controlling formation conditions to produce a mixture of condensable hydrocarbons and H2, wherein a partial pressure of H2 within the mixture is greater than about 0.5 bars.

835. The method of claim 802, wherein a partial pressure of H2 is measured when the mixture is at a production well.

836. The method of claim 802, further comprising altering a pressure within the formation to inhibit production of hydrocarbons from the formation having carbon numbers greater than about 25.

837. The method of claim 802, wherein controlling formation conditions comprises recirculating a portion of hydrogen from the mixture into the formation.

838. The method of claim 802, further comprising:

providing H2 to the heated section to hydrogenate hydrocarbons within the section; and

heating a portion of the section with heat from hydrogenation.

839. The method of claim 802, wherein the produced mixture comprises hydrogen and condensable hydrocarbons, the method further comprising hydrogenating a portion of the produced condensable hydrocarbons with at least a portion of the produced hydrogen.

840. The method of claim 802, wherein allowing the heat to transfer comprises increasing a permeability of a majority of the selected section to greater than about 100 millidarcy.

841. The method of claim 802, wherein allowing the heat to transfer comprises substantially uniformly increasing a permeability of a majority of the selected section.

842. The method of claim 802, further comprising controlling the heat to yield greater than about 60% by weight of condensable hydrocarbons, as measured by Fischer Assay.

843. The method of claim 802, wherein producing the mixture comprises producing the mixture in a production well, and wherein at least about 7 heat sources are disposed in the formation for each production well.

844. The method of claim 843, wherein at least about 20 heat sources are disposed in the formation for each production well.

845. The method of claim 802, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, and wherein the unit of heat sources comprises a triangular pattern.

846. The method of claim 802, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, wherein the unit of heat sources comprises a triangular pattern, and wherein a plurality of the units are repeated over an area of the formation to form a repetitive pattern of units.

847. A method of treating an oil shale formation in situ, comprising:

providing heat from one or more heat sources to at least a portion of the formation; to heat a selected section of the formation to an average temperature above about 270° C.;

allowing the heat to transfer from the one or more heat sources to the selected section of the formation;

controlling the heat from the one or more heat sources such that an average heating rate of the selected section is less than about 3° C. per day during pyrolysis; and

producing a mixture from the formation.

848. The method of claim 847, wherein the one or more heat sources comprise at least two heat sources, and wherein superposition of heat from at least the two heat sources pyrolyzes at least some hydrocarbons within the selected section of the formation.

849. The method of claim 847, wherein the one or more heat sources comprise electrical heaters.

850. The method of claim 847, further comprising supplying electricity to the electrical heaters substantially during non-peak hours.

851. The method of claim 847, wherein the one or more heat sources comprise surface burners.

852. The method of claim 847, wherein the one or more heat sources comprise flameless distributed combustors.

853. The method of claim 847, wherein the one or more heat sources comprise natural distributed combustors.

854. The method of claim 847, further comprising controlling a pressure and a temperature within at least a majority of the selected section of the formation, wherein the pressure is controlled as a function of temperature, or the temperature is controlled as a function of pressure.

855. The method of claim 847, wherein the heat is further controlled such that an average heating rate of the selected section is less than about 3° C./day until production of condensable hydrocarbons substantially ceases.

856. The method of claim 847, wherein the heat is further controlled such that an average heating rate of the selected section is less than about 1.5° C. per day during pyrolysis.

857. The method of claim 847, wherein the heat is further controlled such that an average heating rate of the selected section is less than about 1° C. per day during pyrolysis.

858. The method of claim 847, wherein providing heat from the one or more heat sources to at least the portion of formation comprises:

heating a selected volume (V) of the oil shale formation from the one or more heat sources, wherein the formation has an average heat capacity (Cv), and wherein the heating pyrolyzes at least some hydrocarbons within the selected volume of the formation; and

wherein heating energy/day provided to the volume is equal to or less than Pwr, wherein Pwr is calculated by the equation:

Pwr=h*V*Cv*ρB

wherein Pwr is the heating energy/day, h is an average heating rate of the formation, ρB is formation bulk density.

860. The method of claim 847, wherein providing heat from the one or more heat sources comprises heating the selected section such that a thermal conductivity of at least a portion of the selected section is greater than about 0.5 W/(m° C.).

861. The method of claim 847, wherein the produced mixture comprises condensable hydrocarbons having an API gravity of at least about 25°.

862. The method of claim 847, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 0.1% by weight to about 15% by weight of the condensable hydrocarbons are olefins.

863. The method of claim 847, wherein the produced mixture comprises non-condensable hydrocarbons, and wherein about 0.1% by weight to about 15% by weight of the non-condensable hydrocarbons are olefins.

864. The method of claim 847, wherein the produced mixture comprises non-condensable hydrocarbons, wherein a molar ratio of ethene to ethane in the non-condensable hydrocarbons is less than about 0.15, and wherein the ratio of ethene to ethane is greater than about 0.001.

865. The method of claim 847, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is nitrogen.

866. The method of claim 847, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is oxygen.

867. The method of claim 847, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is sulfur.

868. The method of claim 847, wherein the produced mixture comprises condensable hydrocarbons, wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons comprise oxygen containing compounds, and wherein the oxygen containing compounds comprise phenols.

869. The method of claim 847, wherein the produced mixture comprises condensable hydrocarbons, and wherein greater than about 20% by weight of the condensable hydrocarbons are aromatic compounds.

870. The method of claim 847, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 5% by weight of the condensable hydrocarbons comprises multi-ring aromatics with more than two rings.

871. The method of claim 847, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 0.3% by weight of the condensable hydrocarbons are asphaltenes.

872. The method of claim 847, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons are cycloalkanes.

873. The method of claim 847, wherein the produced mixture comprises a non-condensable component, wherein the non-condensable component comprises hydrogen, wherein the hydrogen is greater than about 10% by volume of the non-condensable component, and wherein the hydrogen is less than about 80% by volume of the non-condensable component.

874. The method of claim 847, wherein the produced mixture comprises ammonia, and wherein greater than about 0.05% by weight of the produced mixture is ammonia.

875. The method of claim 847, wherein the produced mixture comprises ammonia, and wherein the ammonia is used to produce fertilizer.

876. The method of claim 847, further comprising controlling a pressure within at least a majority of the selected section of the formation, wherein the controlled pressure is at least about 2.0 bars absolute.

877. The method of claim 847, further comprising controlling formation conditions to produce a mixture of condensable hydrocarbons and H2, wherein a partial pressure of H2 within the mixture is greater than about 0.5 bars.

878. The method of claim 877, wherein the partial pressure of H2 is measured when the mixture is at a production well.

879. The method of claim 847, further comprising altering a pressure within the formation to inhibit production of hydrocarbons from the formation having carbon numbers greater than about 25.

880. The method of claim 847, wherein controlling formation conditions comprises recirculating a portion of hydrogen from the mixture into the formation.

881. The method of claim 847, further comprising:

providing hydrogen (H2) to the heated section to hydrogenate hydrocarbons within the section; and

heating a portion of the section with heat from hydrogenation.

882. The method of claim 847, wherein the produced mixture comprises hydrogen and condensable hydrocarbons, the method further comprising hydrogenating a portion of the produced condensable hydrocarbons with at least a portion of the produced hydrogen.

883. The method of claim 847, wherein allowing the heat to transfer comprises increasing a permeability of a majority of the selected section to greater than about 100 millidarcy.

884. The method of claim 847, wherein allowing the heat to transfer comprises substantially uniformly increasing a permeability of a majority of the selected section.

885. The method of claim 847, further comprising controlling the heat to yield greater than about 60% by weight of condensable hydrocarbons, as measured by Fischer Assay.

886. The method of claim 847, wherein producing the mixture comprises producing the mixture in a production well, and wherein at least about 7 heat sources are disposed in the formation for each production well.

887. The method of claim 886, wherein at least about 20 heat sources are disposed in the formation for each production well.

888. The method of claim 847, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, and wherein the unit of heat sources comprises a triangular pattern.

889. The method of claim 847, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, wherein the unit of heat sources comprises a triangular pattern, and wherein a plurality of the units are repeated over an area of the formation to form a repetitive pattern of units.

890. A method of treating an oil shale formation in situ, comprising:

providing heat from one or more heat sources to at least a portion of the formation;

allowing the heat to transfer from the one or more heat sources to a selected section of the formation;

producing a mixture from the formation through at least one production well;

monitoring a temperature at or in the production well; and

controlling heat input to raise the monitored temperature at a rate of less than about 3° C. per day.

891. The method of claim 890, wherein the one or more heat sources comprise at least two heat sources, and wherein superposition of heat from at least the two heat sources pyrolyzes at least some hydrocarbons within the selected section of the formation.

892. The method of claim 890, wherein the one or more heat sources comprise electrical heaters.

893. The method of claim 890, wherein the one or more heat sources comprise surface burners.

894. The method of claim 890, wherein the one or more heat sources comprise flameless distributed combustors.

895. The method of claim 890, wherein the one or more heat sources comprise natural distributed combustors.

896. The method of claim 890, further comprising controlling a pressure and a temperature within at least a majority of the selected section of the formation, wherein the pressure is controlled as a function of temperature, or the temperature is controlled as a function of pressure.

897. The method of claim 890, wherein the heat is controlled such that an average heating rate of the selected section is less than about 1° C. per day during pyrolysis.

898. The method of claim 890, wherein providing heat from the one or more heat sources to at least the portion of formation comprises:

heating a selected volume (V) of the oil shale formation from the one or more heat sources, wherein the formation has an average heat capacity (Cv), and wherein the heating pyrolyzes at least some hydrocarbons within the selected volume of the formation; and

wherein heating energy/day provided to the volume is equal to or less than Pwr, wherein Pwr is calculated by the equation:

Pwr=h*V*Cv*ρB

wherein Pwr is the heating energy/day, h is an average heating rate of the formation, ρB is formation bulk density.

900. The method of claim 890, wherein providing heat from the one or more heat sources comprises heating the selected section such that a thermal conductivity of at least a portion of the selected section is greater than about 0.5 W/(m° C.).

901. The method of claim 890, wherein the produced mixture comprises condensable hydrocarbons having an API gravity of at least about 25°.

902. The method of claim 890, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 0.1% by weight to about 15% by weight of the condensable hydrocarbons are olefins.

903. The method of claim 890, wherein the produced mixture comprises non-condensable hydrocarbons, wherein a molar ratio of ethene to ethane in the non-condensable hydrocarbons is less than about 0.15, and wherein the ratio of ethene to ethane is greater than about 0.001.

904. The method of claim 890, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is nitrogen.

905. The method of claim 890, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is oxygen.

906. The method of claim 890, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is sulfur.

907. The method of claim 890, wherein the produced mixture comprises condensable hydrocarbons, wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons comprise oxygen containing compounds, and wherein the oxygen containing compounds comprise phenols.

908. The method of claim 890, wherein the produced mixture comprises condensable hydrocarbons, and wherein greater than about 20% by weight of the condensable hydrocarbons are aromatic compounds.

909. The method of claim 890, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 5% by weight of the condensable hydrocarbons comprises multi-ring aromatics with more than two rings.

910. The method of claim 890, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 0.3% by weight of the condensable hydrocarbons are asphaltenes.

911. The method of claim 890, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons are cycloalkanes.

912. The method of claim 890, wherein the produced mixture comprises a non-condensable component, wherein the non-condensable component comprises hydrogen, wherein the hydrogen is greater than about 10% by volume of the non-condensable component, and wherein the hydrogen is less than about 80% by volume of the non-condensable component.

913. The method of claim 890, wherein the produced mixture comprises ammonia, and wherein greater than about 0.05% by weight of the produced mixture is ammonia.

914. The method of claim 890, wherein the produced mixture comprises ammonia, and wherein the ammonia is used to produce fertilizer.

915. The method of claim 890, further comprising controlling a pressure within at least a majority of the selected section of the formation, wherein the controlled pressure is at least about 2.0 bars absolute.

916. The method of claim 890, further comprising controlling formation conditions to produce a mixture of condensable hydrocarbons and H2, wherein a partial pressure of H2 within the mixture is greater than about 0.5 bars.

917. The method of claim 916, wherein the partial pressure of H2 is measured when the mixture is at a production well.

918. The method of claim 890, further comprising altering a pressure within the formation to inhibit production of hydrocarbons from the formation having carbon numbers greater than about 25.

919. The method of claim 890, wherein controlling formation conditions comprises recirculating a portion of hydrogen from the mixture into the formation.

920. The method of claim 890, further comprising:

providing H2 to the heated section to hydrogenate hydrocarbons within the section; and

heating a portion of the section with heat from hydrogenation.

921. The method of claim 890, wherein the produced mixture comprises hydrogen and condensable hydrocarbons, the method further comprising hydrogenating a portion of the produced condensable hydrocarbons with at least a portion of the produced hydrogen.

922. The method of claim 890, wherein allowing the heat to transfer comprises increasing a permeability of a majority of the selected section to greater than about 100 millidarcy.

923. The method of claim 890, wherein allowing the heat to transfer comprises substantially uniformly increasing a permeability of a majority of the selected section.

924. The method of claim 890, further comprising controlling the heat to yield greater than about 60% by weight of condensable hydrocarbons, as measured by Fischer Assay.

925. The method of claim 890, wherein producing the mixture comprises producing the mixture in a production well, and wherein at least about 7 heat sources are disposed in the formation for each production well.

926. The method of claim 925, wherein at least about 20 heat sources are disposed in the formation for each production well.

927. The method of claim 890, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, and wherein the unit of heat sources comprises a triangular pattern.

928. The method of claim 890, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, wherein the unit of heat sources comprises a triangular pattern, and wherein a plurality of the units are repeated over an area of the formation to form a repetitive pattern of units.

929. A method of treating an oil shale formation in situ, comprising:

heating a portion of the formation to a temperature sufficient to support oxidation of hydrocarbons within the portion, wherein the portion is located substantially adjacent to a wellbore;

flowing an oxidant through a conduit positioned within the wellbore to a heat source zone within the portion, wherein the heat source zone supports an oxidation reaction between hydrocarbons and the oxidant;

reacting a portion of the oxidant with hydrocarbons to generate heat; and

transferring generated heat substantially by conduction to a pyrolysis zone of the formation to pyrolyze at least a portion of the hydrocarbons within the pyrolysis zone.

930. The method of claim 929, wherein heating the portion of the formation comprises raising a temperature of the portion above about 400° C.

931. The method of claim 929, wherein the conduit comprises critical flow orifices, the method further comprising flowing the oxidant through the critical flow orifices to the heat source zone.

932. The method of claim 929, further comprising removing reaction products from the heat source zone through the wellbore.

933. The method of claim 929, further comprising removing excess oxidant from the heat source zone to inhibit transport of the oxidant to the pyrolysis zone.

934. The method of claim 929, further comprising transporting the oxidant from the conduit to the heat source zone substantially by diffusion.

935. The method of claim 929, further comprising heating the conduit with reaction products being removed through the wellbore.

938. The method of claim 929, wherein the oxidant comprises a fluid substantially free of nitrogen.

939. The method of claim 929, further comprising limiting an amount of oxidant to maintain a temperature of the heat source zone less than about 1200° C.

940. The method of claim 929, wherein heating the portion of the formation comprises electrically heating the formation.

941. The method of claim 929, wherein heating the portion of the formation comprises heating the portion using exhaust gases from a surface burner.

942. The method of claim 929, wherein heating the portion of the formation comprises heating the portion with a flameless distributed combustor.

943. The method of claim 929, further comprising controlling a pressure and a temperature within at least a majority of the pyrolysis zone, wherein the pressure is controlled as a function of temperature, or the temperature is controlled as a function of pressure.

944. The method of claim 929, further comprising controlling the heat such that an average heating rate of the pyrolysis zone is less than about 1° C. per day during pyrolysis.

945. The method of claim 929, wherein heating the portion comprises heating the pyrolysis zone such that a thermal conductivity of at least a portion of the pyrolysis zone is greater than about 0.5 W/(m° C.).

946. The method of claim 929, further comprising controlling a pressure within at least a majority of the pyrolysis zone of the formation, wherein the controlled pressure is at least about 2.0 bars absolute.

947. The method of claim 929, further comprising:

providing hydrogen (H2) to the pyrolysis zone to hydrogenate hydrocarbons within the pyrolysis zone; and

heating a portion of the pyrolysis zone with heat from hydrogenation.

948. The method of claim 929, wherein transferring generated heat comprises increasing a permeability of a majority of the pyrolysis zone to greater than about 100 millidarcy.

949. The method of claim 929, wherein transferring generated heat comprises substantially uniformly increasing a permeability of a majority of the pyrolysis zone.

950. The method of claim 929, wherein the heating is controlled to yield greater than about 60% by weight of condensable hydrocarbons, as measured by Fischer Assay.

951. The method of claim 929, wherein the wellbore is located along strike to reduce pressure differentials along a heated length of the wellbore.

952. The method of claim 929, wherein the wellbore is located along strike to increase uniformity of heating along a heated length of the wellbore.

953. The method of claim 929, wherein the wellbore is located along strike to increase control of heating along a heated length of the wellbore.

954. A method of treating an oil shale formation in situ, comprising:

heating a portion of the formation to a temperature sufficient to support reaction of hydrocarbons within the portion of the formation with an oxidant;

flowing the oxidant into a conduit, and wherein the conduit is connected such that the oxidant can flow from the conduit to the hydrocarbons;

allowing the oxidant and the hydrocarbons to react to produce heat in a heat source zone;

allowing heat to transfer from the heat source zone to a pyrolysis zone in the formation to pyrolyze at least a portion of the hydrocarbons within the pyrolysis zone; and

removing reaction products such that the reaction products are inhibited from flowing from the heat source zone to the pyrolysis zone.

955. The method of claim 954, wherein heating the portion of the formation comprises raising the temperature of the portion above about 400° C.

956. The method of claim 954, wherein heating the portion of the formation comprises electrically heating the formation.

957. The method of claim 954, wherein heating the portion of the formation comprises heating the portion using exhaust gases from a surface burner.

958. The method of claim 954, wherein the conduit comprises critical flow orifices, the method further comprising flowing the oxidant through the critical flow orifices to the heat source zone.

959. The method of claim 954, wherein the conduit is located within a wellbore, wherein removing reaction products comprises removing reaction products from the heat source zone through the wellbore.

960. The method of claim 954, further comprising removing excess oxidant from the heat source zone to inhibit transport of the oxidant to the pyrolysis zone.

961. The method of claim 954, further comprising transporting the oxidant from the conduit to the heat source zone substantially by diffusion.

962. The method of claim 954, wherein the conduit is located within a wellbore, the method further comprising heating the conduit with reaction products being removed through the wellbore to raise a temperature of the oxidant passing through the conduit.

965. The method of claim 954, wherein the oxidant comprises a fluid substantially free of nitrogen.

966. The method of claim 954, further comprising limiting an amount of oxidant to maintain a temperature of the heat source zone less than about 1200° C.

967. The method of claim 954, further comprising limiting an amount of oxidant to maintain a temperature of the heat source zone at a temperature that inhibits production of oxides of nitrogen.

968. The method of claim 954, wherein heating a portion of the formation to a temperature sufficient to support oxidation of hydrocarbons within the portion further comprises heating with a flameless distributed combustor.

969. The method of claim 954, further comprising controlling a pressure and a temperature within at least a majority of the pyrolysis zone of the formation, wherein the pressure is controlled as a function of temperature, or the temperature is controlled as a function of pressure.

970. The method of claim 954, further comprising controlling the heat such that an average heating rate of the pyrolysis zone is less than about 1° C. per day during pyrolysis.

972. The method of claim 954, wherein allowing heat to transfer comprises heating the pyrolysis zone such that a thermal conductivity of at least a portion of the pyrolysis zone is greater than about 0.5 W/(m° C.).

973. The method of claim 954, further comprising controlling a pressure within at least a majority of the pyrolysis zone, wherein the controlled pressure is at least about 2.0 bars absolute.

974. The method of claim 954, further comprising:

providing hydrogen (H2) to the pyrolysis zone to hydrogenate hydrocarbons within the pyrolysis zone; and

heating a portion of the pyrolysis zone with heat from hydrogenation.

975. The method of claim 954, wherein allowing the heat to transfer comprises increasing a permeability of a majority of the pyrolysis zone to greater than about 100 millidarcy.

976. The method of claim 954, wherein allowing the heat to transfer comprises substantially uniformly increasing a permeability of a majority of the pyrolysis zone.

977. The method of claim 954, further comprising controlling the heat to yield greater than about 60% by weight of condensable hydrocarbons, as measured by Fischer Assay.

978. An in situ method for heating an oil shale formation, comprising:

heating a portion of the formation to a temperature sufficient to support reaction of hydrocarbons within the portion of the formation with an oxidizing fluid, wherein the portion is located substantially adjacent to an opening in the formation;

providing the oxidizing fluid to a heat source zone in the formation;

allowing the oxidizing gas to react with at least a portion of the hydrocarbons at the heat source zone to generate heat in the heat source zone; and

transferring the generated heat substantially by conduction from the heat source zone to a pyrolysis zone in the formation.

979. The method of claim 978, further comprising transporting the oxidizing fluid through the heat source zone by diffusion.

980. The method of claim 978, further comprising directing at least a portion of the oxidizing fluid into the opening through orifices of a conduit disposed in the opening.

981. The method of claim 978, further comprising controlling a flow of the oxidizing fluid with critical flow orifices of a conduit disposed in the opening such that a rate of oxidation is controlled.

982. The method of claim 978, wherein a conduit is disposed within the opening, the method further comprising removing an oxidation product from the formation through the conduit.

983. The method of claim 978, wherein a conduit is disposed within the opening, the method further comprising removing an oxidation product from the formation through the conduit and transferring substantial heat from the oxidation product in the conduit to the oxidizing fluid in the conduit.

984. The method of claim 978, wherein a conduit is disposed within the opening, the method further comprising removing an oxidation product from the formation through the conduit, wherein a flow rate of the oxidizing fluid in the conduit is approximately equal to a flow rate of the oxidation product in the conduit.

985. The method of claim 978, wherein a conduit is disposed within the opening, the method further comprising removing an oxidation product from the formation through the conduit and controlling a pressure between the oxidizing fluid and the oxidation product in the conduit to reduce contamination of the oxidation product by the oxidizing fluid.

986. The method of claim 978, wherein a center conduit is disposed within an outer conduit, and wherein the outer conduit is disposed within the opening, the method further comprising providing the oxidizing fluid into the opening through the center conduit and removing an oxidation product through the outer conduit.

987. The method of claim 978, wherein the heat source zone extends radially from the opening a width of less than approximately 0.15 m.

988. The method of claim 978, wherein heating the portion comprises applying electrical current to an electric heater disposed within the opening.

989. The method of claim 978, wherein the pyrolysis zone is substantially adjacent to the heat source zone.

990. The method of claim 978, further comprising controlling a pressure and a temperature within at least a majority of the pyrolysis zone of the formation, wherein the pressure is controlled as a function of temperature, or the temperature is controlled as a function of pressure.

991. The method of claim 978, further comprising controlling the heat such that an average heating rate of the pyrolysis zone is less than about 1° C. per day during pyrolysis.

993. The method of claim 978, wherein allowing heat to transfer comprises heating the portion such that a thermal conductivity of at least a portion of the pyrolysis zone is greater than about 0.5 W/(m° C.).

994. The method of claim 978, further comprising controlling a pressure within at least a majority of the pyrolysis zone, wherein the controlled pressure is at least about 2.0 bars absolute.

995. The method of claim 978, further comprising:

providing hydrogen (H2) to the pyrolysis zone to hydrogenate hydrocarbons within the pyrolysis zone; and

heating a portion of the pyrolysis zone with heat from hydrogenation.

996. The method of claim 978, wherein allowing the heat to transfer comprises increasing a permeability of a majority of the pyrolysis zone to greater than about 100 millidarcy.

997. The method of claim 978, wherein allowing the heat to transfer comprises substantially uniformly increasing a permeability of a majority of the pyrolysis zone.

998. The method of claim 978, further comprising controlling the heat to yield greater than about 60% by weight of condensable hydrocarbons, as measured by Fischer Assay.

999. A method of treating an oil shale formation in situ, comprising:

providing heat from one or more heat sources to at least a portion of the formation;

allowing the heat to transfer from the one or more heat sources to a selected section of the formation;

producing a mixture from the formation; and

maintaining an average temperature within the selected section above a minimum pyrolysis temperature and below a vaporization temperature of hydrocarbons having carbon numbers greater than 25 to inhibit production of a substantial amount of hydrocarbons having carbon numbers greater than 25 in the mixture.

1000. The method of claim 999, wherein the one or more heat sources comprise at least two heat sources, and wherein superposition of heat from at least the two heat sources pyrolyzes at least some hydrocarbons within the selected section of the formation.

1001. The method of claim 999, wherein maintaining the average temperature within the selected section comprises maintaining the temperature within a pyrolysis temperature range.

1002. The method of claim 999, wherein the one or more heat sources comprise electrical heaters.

1003. The method of claim 999, wherein the one or more heat sources comprise surface burners.

1004. The method of claim 999, wherein the one or more heat sources comprise flameless distributed combustors.

1005. The method of claim 999, wherein the one or more heat sources comprise natural distributed combustors.

1006. The method of claim 999, wherein the minimum pyrolysis temperature is greater than about 270° C.

1007. The method of claim 999, wherein the vaporization temperature is less than approximately 450° C. at atmospheric pressure.

1008. The method of claim 999, further comprising controlling a pressure and a temperature within at least a majority of the selected section of the formation, wherein the pressure is controlled as a function of temperature, or the temperature is controlled as a function of pressure.

1009. The method of claim 999, further comprising controlling the heat such that an average heating rate of the selected section is less than about 1° C. per day during pyrolysis.

1010. The method of claim 999, wherein providing heat from the one or more heat sources to at least the portion of formation comprises:

heating a selected volume (V) of the oil shale formation from the one or more heat sources, wherein the formation has an average heat capacity (Cv), and wherein the heating pyrolyzes at least some hydrocarbons within the selected volume of the formation; and

wherein heating energy/day provided to the volume is equal to or less than Pwr, wherein Pwr is calculated by the equation:

Pwr=h*V*Cv*ρB

wherein Pwr is the heating energy/day, h is an average heating rate of the formation, ρB is formation bulk density, and wherein the heating rate is less than about 10° C./day.

1012. The method of claim 999, wherein providing heat from the one or more heat sources comprises heating the selected formation such that a thermal conductivity of at least a portion of the selected section is greater than about 0.5 W/(m° C.).

1013. The method of claim 999, wherein the produced mixture comprises condensable hydrocarbons having an API gravity of at least about 25°.

1014. The method of claim 999, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 0.1% by weight to about 15% by weight of the condensable hydrocarbons are olefins.

1015. The method of claim 999, wherein the produced mixture comprises non-condensable hydrocarbons, and wherein about 0.1% by weight to about 15% by weight of the non-condensable hydrocarbons are olefins.

1016. The method of claim 999, wherein the produced mixture comprises non-condensable hydrocarbons, wherein a molar ratio of ethene to e thane in the non-condensable hydrocarbons is less than about 0.15, and wherein the ratio of ethene to ethane is greater than about 0.001.

1017. The method of claim 999, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is nitrogen.

1018. The method of claim 999, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is oxygen.

1019. The method of claim 999, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is sulfur.

1020. The method of claim 999, wherein the produced mixture comprises condensable hydrocarbons, wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons comprise oxygen containing compounds, and wherein the oxygen containing compounds comprise phenols.

1021. The method of claim 999, wherein the produced mixture comprises condensable hydrocarbons, and wherein greater than about 20% by weight of the condensable hydrocarbons are aromatic compounds.

1022. The method of claim 999, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 5% by weight of the condensable hydrocarbons comprises multi-ring aromatics with more than two rings.

1023. The method of claim 999, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 0.3% by weight of the condensable hydrocarbons are asphaltenes.

1024. The method of claim 999, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons are cycloalkanes.

1025. The method of claim 999, wherein the produced mixture comprises a non-condensable component, wherein the non-condensable component comprises hydrogen, wherein the hydrogen is greater than about 10% by volume of the non-condensable component, and wherein the hydrogen is less than about 80% by volume of the non-condensable component.

1026. The method of claim 999, wherein the produced mixture comprises ammonia, and wherein greater than about 0.05% by weight of the produced mixture is ammonia.

1027. The method of claim 999, wherein the produced mixture comprises ammonia, and wherein the ammonia is used to produce fertilizer.

1028. The method of claim 999, further comprising controlling a pressure within at least a majority of the selected section of the formation, wherein the controlled pressure is at least about 2.0 bars absolute.

1029. The method of claim 999, further comprising controlling formation conditions to produce a mixture of condensable hydrocarbons and H2, wherein a partial pressure of H2 within the mixture is greater than about 0.5 bars.

1030. The method of claim 1029, wherein the partial pressure of H2 is measured when the mixture is at a production well.

1031. The method of claim 999, wherein controlling formation conditions comprises recirculating a portion of hydrogen from the mixture into the formation.

1032. The method of claim 999, further comprising:

providing hydrogen (H2) to the heated section to hydrogenate hydrocarbons within the section; and

heating a portion of the section with heat from hydrogenation.

1033. The method of claim 999, wherein the produced mixture comprises hydrogen and condensable hydrocarbons, the method further comprising hydrogenating a portion of the produced condensable hydrocarbons with at least a portion of the produced hydrogen.

1034. The method of claim 999, wherein allowing the heat to transfer comprises increasing a permeability of a majority of the selected section to greater than about 100 millidarcy.

1035. The method of claim 999, wherein allowing the heat to transfer comprises substantially uniformly increasing a permeability of a majority of the selected section.

1036. The method of claim 999, further comprising controlling the heat to yield greater than about 60% by weight of condensable hydrocarbons, as measured by Fischer Assay.

1037. The method of claim 999, wherein producing the mixture comprises producing the mixture in a production well, and wherein at least about 7 heat sources are disposed in the formation for each production well.

1038. The method of claim 1037, wherein at least about 20 heat sources are disposed in the formation for each production well.

1039. The method of claim 999, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, and wherein the unit of heat sources comprises a triangular pattern.

1040. The method of claim 999, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, wherein the unit of heat sources comprises a triangular pattern, and wherein a plurality of the units are repeated over an area of the formation to form a repetitive pattern of units.

1041. A method of treating an oil shale formation in situ, comprising:

providing heat from one or more heat sources to at least a portion of the formation;

allowing the heat to transfer from the one or more heat sources to a selected section of the formation;

controlling a pressure within the formation to inhibit production of hydrocarbons from the formation having carbon numbers greater than 25; and

producing a mixture from the formation.

1042. The method of claim 1041, wherein the one or more heat sources comprise at least two heat sources, and wherein superposition of heat from at least the two heat sources pyrolyzes at least some hydrocarbons within the selected section of the formation.

1043. The method of claim 1041, wherein the one or more heat sources comprise electrical heaters.

1044. The method of claim 1041, wherein the one or more heat sources comprise surface burners.

1045. The method of claim 1041, wherein the one or more heat sources comprise flameless distributed combustors.

1046. The method of claim 1041, wherein the one or more heat sources comprise natural distributed combustors.

1047. The method of claim 1041, further comprising controlling a temperature within at least a majority of the selected section of the formation, wherein the pressure is controlled as a function of temperature, or the temperature is controlled as a function of pressure.

1048. The method of claim 1047, wherein controlling the temperature comprises maintaining a temperature within the selected section within a pyrolysis temperature range.

1049. The method of claim 1041, further comprising controlling the heat such that an average heating rate of the selected section is less than about 1° C. per day during pyrolysis.

1050. The method of claim 1041, wherein providing heat from the one or more heat sources to at least the portion of formation comprises:

heating a selected volume (V) of the oil shale formation from the one or more heat sources, wherein the formation has an average heat capacity (Cv), and wherein the heating pyrolyzes at least some hydrocarbons within the selected volume of the formation; and

wherein heating energy/day provided to the volume is equal to or less than Pwr, wherein Pwr is calculated by the equation:

Pwr=h*V*Cv*ρB

wherein Pwr is the heating energy/day, h is an average heating rate of the formation, ρB is formation bulk density, and wherein the heating rate is less than about 10° C./day.

1052. The method of claim 1041, wherein providing heat from the one or more heat sources comprises heating the selected formation such that a thermal conductivity of at least a portion of the selected section is greater than about 0.5 W/(m° C.).

1053. The method of claim 1041, wherein the produced mixture comprises condensable hydrocarbons having an API gravity of at least about 25°.

1054. The method of claim 1041, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 0.1% by weight to about 15% by weight of the condensable hydrocarbons are olefins.

1055. The method of claim 1041, wherein the produced mixture comprises non-condensable hydrocarbons, and wherein about 0.1% by weight to about 15% by weight of the non-condensable hydrocarbons are olefins.

1056. The method of claim 1041, wherein the produced mixture comprises non-condensable hydrocarbons, wherein a molar ratio of ethene to ethane in the non-condensable hydrocarbons is less than about 0.15, and wherein the ratio of ethene to ethane is greater than about 0.001.

1057. The method of claim 1041, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is nitrogen.

1058. The method of claim 1041, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is oxygen.

1059. The method of claim 1041, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is sulfur.

1060. The method of claim 1041, wherein the produced mixture comprises condensable hydrocarbons, wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons comprise oxygen containing compounds, and wherein the oxygen containing compounds comprise phenols.

1061. The method of claim 1041, wherein the produced mixture comprises condensable hydrocarbons, and wherein greater than about 20% by weight of the condensable hydrocarbons are aromatic compounds.

1062. The method of claim 1041, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 5% by weight of the condensable hydrocarbons comprises multi-ring aromatics with more than two rings.

1063. The method of claim 1041, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 0.3% by weight of the condensable hydrocarbons are asphaltenes.

1064. The method of claim 1041, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons are cycloalkanes.

1065. The method of claim 1041, wherein the produced mixture comprises a non-condensable component, wherein the non-condensable component comprises hydrogen, wherein the hydrogen is greater than about 10% by volume of the non-condensable component, and wherein the hydrogen is less than about 80% by volume of the non-condensable component.

1066. The method of claim 1041, wherein the produced mixture comprises ammonia, and wherein greater than about 0.05% by weight of the produced mixture is ammonia.

1067. The method of claim 1041, wherein the produced mixture comprises ammonia, and wherein the ammonia is used to produce fertilizer.

1068. The method of claim 1041, further comprising controlling the pressure within at least a majority of the selected section of the formation, wherein the controlled pressure is at least about 2.0 bars absolute.

1069. The method of claim 1041, further comprising controlling formation conditions to produce a mixture of condensable hydrocarbons and H2, wherein a partial pressure of H2 within the mixture is greater than about 0.5 bars.

1070. The method of claim 1069, wherein the partial pressure of H2 is measured when the mixture is at a production well.

1071. The method of claim 1041, wherein controlling formation conditions comprises recirculating a portion of hydrogen from the mixture into the formation.

1072. The method of claim 1041, further comprising:

providing hydrogen (H2) to the heated section to hydrogenate hydrocarbons within the section; and

heating a portion of the section with heat from hydrogenation.

1073. The method of claim 1041, wherein the produced mixture comprises hydrogen and condensable hydrocarbons, the method further comprising hydrogenating a portion of the produced condensable hydrocarbons with at least a portion of the produced hydrogen.

1074. The method of claim 1041, wherein allowing the heat to transfer comprises increasing a permeability of a majority of the selected section to greater than about 100 millidarcy.

1075. The method of claim 1041, wherein allowing the heat to transfer comprises substantially uniformly increasing a permeability of a majority of the selected section.

1076. The method of claim 1041, further comprising controlling the heat to yield greater than about 60% by weight of condensable hydrocarbons, as measured by Fischer Assay.

1077. The method of claim 1041, wherein producing the mixture comprises producing the mixture in a production well, and wherein at least about 7 heat sources are disposed in the formation for each production well.

1078. The method of claim 1077, wherein at least about 20 heat sources are disposed in the formation for each production well.

1079. The method of claim 1041, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, and wherein the unit of heat sources comprises a triangular pattern.

1080. The method of claim 1041, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, wherein the unit of heat sources comprises a triangular pattern, and wherein a plurality of the units are repeated over an area of the formation to form a repetitive pattern of units.

1081. A method of treating an oil shale formation in situ, comprising:

providing heat from one or more heat sources to at least a portion of the formation;

allowing the heat to transfer from the one or more heat sources to a selected section of the formation; and

producing a mixture from the formation, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 0.1% by weight to about 15% by weight of the condensable hydrocarbons are olefins.

1082. The method of claim 1081, wherein the one or more heat sources comprise at least two heat sources, and wherein superposition of heat from at least the two heat sources pyrolyzes at least some hydrocarbons within the selected section of the formation.

1083. The method of claim 1081, wherein the one or more heat sources comprise electrical heaters.

1084. The method of claim 1081, wherein the one or more heat sources comprise surface burners.

1085. The method of claim 1081, wherein the one or more heat sources comprise flameless distributed combustors.

1086. The method of claim 1081, wherein the one or more heat sources comprise natural distributed combustors.

1087. The method of claim 1081, further comprising controlling a pressure and a temperature within at least a majority of the selected section of the formation, wherein the pressure is controlled as a function of temperature, or the temperature is controlled as a function of pressure.

1088. The method of claim 1081, wherein controlling the temperature comprises maintaining the temperature within the selected section within a pyrolysis temperature range.

1089. The method of claim 1081, further comprising controlling the heat such that an average heating rate of the selected section is less than about 1° C. per day during pyrolysis.

1090. The method of claim 1081, wherein providing heat from the one or more heat sources to at least the portion of formation comprises:

heating a selected volume (V) of the oil shale formation from the one or more heat sources, wherein the formation has an average heat capacity (Cv), and wherein the heating pyrolyzes at least some hydrocarbons within the selected volume of the formation; and

wherein heating energy/day provided to the volume is equal to or less than Pwr, wherein Pwr is calculated by the equation:

Pwr=h*V*Cv*ρB

wherein Pwr is the heating energy/day, h is an average heating rate of the formation, ρB is formation bulk density, and wherein the heating rate is less than about 10° C./day.

1092. The method of claim 1081, wherein providing heat from the one or more heat sources comprises heating the selected formation such that a thermal conductivity of at least a portion of the selected section is greater than about 0.5 W/(m° C.).

1093. The method of claim 1081, wherein the produced mixture comprises condensable hydrocarbons having an API gravity of at least about 25°.

1094. The method of claim 1081, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 0.1% by weight to about 15% by weight of the condensable hydrocarbons are olefins.

1095. The method of claim 1081, wherein the produced mixture comprises non-condensable hydrocarbons, and wherein about 0.1% by weight to about 15% by weight of the non-condensable hydrocarbons are olefins.

1096. The method of claim 1081, wherein the produced mixture comprises non-condensable hydrocarbons, wherein a molar ratio of ethene to ethane in the non-condensable hydrocarbons is less than about 0.15, and wherein the ratio of ethene to ethane is greater than about 0.001.

1097. The method of claim 1081, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is nitrogen.

1098. The method of claim 1081, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is oxygen.

1099. The method of claim 1081, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is sulfur.

1100. The method of claim 1081, wherein the produced mixture comprises condensable hydrocarbons, wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons comprise oxygen containing compounds, and wherein the oxygen containing compounds comprise phenols.

1101. The method of claim 1081, wherein the produced mixture comprises condensable hydrocarbons, and wherein greater than about 20% by weight of the condensable hydrocarbons are aromatic compounds.

1102. The method of claim 1081, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 5% by weight of the condensable hydrocarbons comprises multi-ring aromatics with more than two rings.

1103. The method of claim 1081, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 0.3% by weight of the condensable hydrocarbons are asphaltenes.

1104. The method of claim 1081, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons are cycloalkanes.

1105. The method of claim 1081, wherein the produced mixture comprises a non-condensable component, wherein the non-condensable component comprises hydrogen, wherein the hydrogen is greater than about 10% by volume of the non-condensable component, and wherein the hydrogen is less than about 80% by volume of the non-condensable component.

1106. The method of claim 1081, wherein the produced mixture comprises ammonia, and wherein greater than about 0.05% by weight of the produced mixture is ammonia.

1107. The method of claim 1081, wherein the produced mixture comprises ammonia, and wherein the ammonia is used to produce fertilizer.

1108. The method of claim 1081, further comprising controlling a pressure within at least a majority of the selected section of the formation, wherein the controlled pressure is at least about 2.0 bars absolute.

1109. The method of claim 1081, further comprising controlling formation conditions to produce a mixture of condensable hydrocarbons and H2, wherein a partial pressure of H2 within the mixture is greater than about 0.5 bars.

1110. The method of claim 1109, wherein the partial pressure of H2 is measured when the mixture is at a production well.

1111. The method of claim 1081, further comprising altering a pressure within the formation to inhibit production of hydrocarbons from the formation having carbon numbers greater than about 25.

1112. The method of claim 1081, wherein controlling formation conditions comprises recirculating a portion of hydrogen from the mixture into the formation.

1113. The method of claim 1081, further comprising:

providing hydrogen (H2) to the heated section to hydrogenate hydrocarbons within the section; and

heating a portion of the section with heat from hydrogenation.

1114. The method of claim 1081, wherein the produced mixture comprises hydrogen and condensable hydrocarbons, the method further comprising hydrogenating a portion of the produced condensable hydrocarbons with at least a portion of the produced hydrogen.

1115. The method of claim 1081, wherein allowing the heat to transfer comprises increasing a permeability of a majority of the selected section to greater than about 100 millidarcy.

1116. The method of claim 1081, wherein allowing the heat to transfer comprises substantially uniformly increasing a permeability of a majority of the selected section.

1117. The method of claim 1081, further comprising controlling the heat to yield greater than about 60% by weight of condensable hydrocarbons, as measured by Fischer Assay.

1118. The method of claim 1081, wherein producing the mixture comprises producing the mixture in a production well, and wherein at least about 7 heat sources are disposed in the formation for each production well.

1119. The method of claim 1118, wherein at least about 20 heat sources are disposed in the formation for each production well.

1120. The method of claim 1081, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, and wherein the unit of heat sources comprises a triangular pattern.

1121. The method of claim 1081, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, wherein the unit of heat sources comprises a triangular pattern, and wherein a plurality of the units are repeated over an area of the formation to form a repetitive pattern of units.

1122. A method of treating an oil shale formation in situ, comprising:

heating a section of the formation to a pyrolysis temperature from at least a first heat source, a second heat source and a third heat source, and wherein the first heat source, the second heat source and the third heat source are located along a perimeter of the section;

controlling heat input to the first heat source, the second heat source and the third heat source to limit a heating rate of the section to a rate configured to produce a mixture from the formation with an olefin content of less than about 15% by weight of condensable fluids (on a dry basis) within the produced mixture; and

producing the mixture from the formation through a production well.

1123. The method of claim 1122, wherein superposition of heat form the first heat source, second heat source, and third heat source pyrolyzes a portion of the hydrocarbons within the formation to fluids.

1124. The method of claim 1122, wherein the pyrolysis temperature is between about 270° C. and about 400° C.

1125. The method of claim 1122, wherein the first heat source is operated for less than about twenty-four hours a day.

1126. The method of claim 1122, wherein the first heat source comprises an electrical heater.

1127. The method of claim 1122, wherein the first heat source comprises a surface burner.

1128. The method of claim 1122, wherein the first heat source comprises a flameless distributed combustor.

1129. The method of claim 1122, wherein the first heat source, second heat source and third heat source are positioned substantially at apexes of an equilateral triangle.

1130. The method of claim 1122, wherein the production well is located substantially at a geometrical center of the first heat source, second heat source, and third heat source.

1131. The method of claim 1122, further comprising a fourth heat source, fifth heat source, and sixth heat source located along the perimeter of the section.

1132. The method of claim 1131, wherein the heat sources are located substantially at apexes of a regular hexagon.

1133. The method of claim 1132, wherein the production well is located substantially at a center of the hexagon.

1134. The method of claim 1122, further comprising controlling a pressure and a temperature within at least a majority of the section of the formation, wherein the pressure is controlled as a function of temperature, or the temperature is controlled as a function of pressure.

1135. The method of claim 1122, wherein controlling the temperature comprises maintaining the temperature within the selected section within a pyrolysis temperature range.

1136. The method of claim 1122, further comprising controlling the heat such that an average heating rate of the section is less than about 3° C. per day during pyrolysis.

1137. The method of claim 1122, further comprising controlling the heat such that an average heating rate of the section is less than about 1° C. per day during pyrolysis.

1138. The method of claim 1122, wherein providing heat from the one or more heat sources to at least the portion of formation comprises:

heating a selected volume (V) of the oil shale formation from the one or more heat sources, wherein the formation has an average heat capacity (Cv), and wherein the heating pyrolyzes at least some hydrocarbons within the selected volume of the formation; and

wherein heating energy/day provided to the volume is equal to or less than Pwr, wherein Pwr is calculated by the equation:

Pwr=h*V*Cv*ρB

wherein Pwr is the heating energy/day, h is an average heating rate of the formation, ρB is formation bulk density, and wherein the heating rate is less than about 10° C./day.

1139. The method of claim 1122, wherein heating the section of the formation comprises transferring heat substantially by conduction.

1140. The method of claim 1122, wherein providing heat from the one or more heat sources comprises heating the section such that a thermal conductivity of at least a portion of the section is greater than about 0.5 W/(m° C.).

1141. The method of claim 1122, wherein the produced mixture comprises condensable hydrocarbons having an API gravity of at least about 25°.

1142. The method of claim 1122, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 0.1% by weight to about 15% by weight of the condensable hydrocarbons are olefins.

1143. The method of claim 1122, wherein the produced mixture comprises non-condensable hydrocarbons, wherein a molar ratio of ethene to ethane in the non-condensable hydrocarbons is less than about 0.15, and wherein the ratio of ethene to ethane is greater than about 0.001.

1144. The method of claim 1122, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is nitrogen.

1145. The method of claim 1122, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is oxygen.

1146. The method of claim 1122, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is sulfur.

1147. The method of claim 1122, wherein the produced mixture comprises condensable hydrocarbons, wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons comprise oxygen containing compounds, and wherein the oxygen containing compounds comprise phenols.

1148. The method of claim 1122, wherein the produced mixture comprises condensable hydrocarbons, and wherein greater than about 20% by weight of the condensable hydrocarbons are aromatic compounds.

1149. The method of claim 1122, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 5% by weight of the condensable hydrocarbons comprises multi-ring aromatics with more than two rings.

1150. The method of claim 1122, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 0.3% by weight of the condensable hydrocarbons are asphaltenes.

1151. The method of claim 1122, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons are cycloalkanes.

1152. The method of claim 1122, wherein the produced mixture comprises a non-condensable component, wherein the non-condensable component comprises hydrogen, wherein the hydrogen is greater than about 10% by volume of the non-condensable component, and wherein the hydrogen is less than about 80% by volume of the non-condensable component.

1153. The method of claim 1122, wherein the produced mixture comprises ammonia, and wherein greater than about 0.05% by weight of the produced mixture is ammonia.

1154. The method of claim 1122, wherein the produced mixture comprises ammonia, and wherein the ammonia is used to produce fertilizer.

1155. The method of claim 1122, further comprising controlling a pressure within at least a majority of the selected section of the formation, wherein the controlled pressure is at least about 2.0 bars absolute.

1156. The method of claim 1122, further comprising controlling formation conditions to produce a mixture of condensable hydrocarbons and H2, wherein a partial pressure of H2 within the mixture is greater than about 0.5 bars.

1157. The method of claim 1156, wherein the partial pressure of H2 is measured when the mixture is at a production well.

1158. The method of claim 1122, further comprising altering a pressure within the formation to inhibit production of hydrocarbons from the formation having carbon numbers greater than about 25.

1159. The method of claim 1122, wherein controlling formation conditions comprises recirculating a portion of hydrogen from the mixture into the formation.

1160. The method of claim 1122, further comprising:

providing hydrogen (H2) to the heated section to hydrogenate hydrocarbons within the section; and

heating a portion of the section with heat from hydrogenation.

1161. The method of claim 1122, wherein the produced mixture comprises hydrogen and condensable hydrocarbons, the method further comprising hydrogenating a portion of the produced condensable hydrocarbons with at least a portion of the produced hydrogen.

1162. The method of claim 1122, wherein heating the section comprises increasing a permeability of a majority of the section to greater than about 100 millidarcy.

1163. The method of claim 1122, wherein heating the section comprises substantially uniformly increasing a permeability of a majority of the section.

1164. The method of claim 1122, further comprising controlling the heat to yield greater than about 60% by weight of condensable hydrocarbons, as measured by Fischer Assay.

1165. The method of claim 1122, wherein producing the mixture comprises producing the mixture in a production well, and wherein at least about 7 heat sources are disposed in the formation for each production well.

1166. The method of claim 1165, wherein at least about 20 heat sources are disposed in the formation for each production well.

1167. The method of claim 1122, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, and wherein the unit of heat sources comprises a triangular pattern.

1168. The method of claim 1122, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, wherein the unit of heat sources comprises a triangular pattern, and wherein a plurality of the units are repeated over an area of the formation to form a repetitive pattern of units.

1169. A method of treating an oil shale formation in situ, comprising:

providing heat from one or more heat sources to at least a portion of the formation;

allowing the heat to transfer from the one or more heat sources to a selected section of the formation; and

producing a mixture from the formation, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is nitrogen.

1170. The method of claim 1169, wherein the one or more heat sources comprise at least two heat sources, and wherein superposition of heat from at least the two heat sources pyrolyzes at least some hydrocarbons within the selected section of the formation.

1171. The method of claim 1169, wherein the one or more heat sources comprise electrical heaters.

1172. The method of claim 1169, wherein the one or more heat sources comprise surface burners.

1173. The method of claim 1169, wherein the one or more heat sources comprise flameless distributed combustors.

1174. The method of claim 1169, wherein the one or more heat sources comprise natural distributed combustors.

1175. The method of claim 1169, further comprising controlling a pressure and a temperature within at least a majority of the selected section of the formation, wherein the pressure is controlled as a function of temperature, or the temperature is controlled as a function of pressure.

1176. The method of claim 1175, wherein controlling the temperature comprises maintaining the temperature within the selected section within a pyrolysis temperature range.

1177. The method of claim 1169, further comprising controlling the heat such that an average heating rate of the selected section is less than about 1° C. per day during pyrolysis.

1178. The method of claim 1169, wherein providing heat from the one or more heat sources to at least the portion of formation comprises:

heating a selected volume (V) of the oil shale formation from the one or more heat sources, wherein the formation has an average heat capacity (Cv), and wherein the heating pyrolyzes at least some hydrocarbons within the selected volume of the formation; and

wherein heating energy/day provided to the volume is equal to or less than Pwr, wherein Pwr is calculated by the equation:

Pwr=h*V*Cv*ρB

wherein Pwr is the heating energy/day, h is an average heating rate of the formation, ρB is formation bulk density, and wherein the heating rate is less than about 10° C./day.

1180. The method of claim 1169, wherein providing heat from the one or more heat sources comprises heating the selected formation such that a thermal conductivity of at least a portion of the selected section is greater than about 0.5 W/(m° C.).

1181. The method of claim 1169, wherein the produced mixture comprises condensable hydrocarbons having an API gravity of at least about 25°.

1182. The method of claim 1169, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 0.1% by weight to about 15% by weight of the condensable hydrocarbons are olefins.

1183. The method of claim 1169, wherein the produced mixture comprises non-condensable hydrocarbons, and wherein about 0.1% by weight to about 15% by weight of the non-condensable hydrocarbons are olefins.

1184. The method of claim 1169, wherein the produced mixture comprises non-condensable hydrocarbons, wherein a molar ratio of ethene to ethane in the non-condensable hydrocarbons is less than about 0.15, and wherein the ratio of ethene to ethane is greater than about 0.001.

1185. The method of claim 1169, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is oxygen.

1186. The method of claim 1169, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is sulfur.

1187. The method of claim 1169, wherein the produced mixture comprises condensable hydrocarbons, wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons comprise oxygen containing compounds, and wherein the oxygen containing compounds comprise phenols.

1188. The method of claim 1169, wherein the produced mixture comprises condensable hydrocarbons, and wherein greater than about 20% by weight of the condensable hydrocarbons are aromatic compounds.

1189. The method of claim 1169, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 5% by weight of the condensable hydrocarbons comprises multi-ring aromatics with more than two rings.

1190. The method of claim 1169, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 0.3% by weight of the condensable hydrocarbons are asphaltenes.

1191. The method of claim 1169, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons are cycloalkanes.

1192. The method of claim 1169, wherein the produced mixture comprises a non-condensable component, wherein the non-condensable component comprises hydrogen, wherein the hydrogen is greater than about 10% by volume of the non-condensable component, and wherein the hydrogen is less than about 80% by volume of the non-condensable component.

1193. The method of claim 1169, wherein the produced mixture comprises ammonia, and wherein greater than about 0.05% by weight of the produced mixture is ammonia.

1194. The method of claim 1169, wherein the produced mixture comprises ammonia, and wherein the ammonia is used to produce fertilizer.

1195. The method of claim 1169, further comprising controlling a pressure within at least a majority of the selected section of the formation, wherein the controlled pressure is at least about 2.0 bars absolute.

1196. The method of claim 1169, further comprising controlling formation conditions to produce a mixture of condensable hydrocarbons and H2, wherein a partial pressure of H2 within the mixture is greater than about 0.5 bars.

1197. The method of claim 1196, wherein the partial pressure of H2 is measured when the mixture is at a production well.

1198. The method of claim 1169, further comprising altering a pressure within the formation to inhibit production of hydrocarbons from the formation having carbon numbers greater than about 25.

1199. The method of claim 1169, wherein controlling formation conditions comprises recirculating a portion of hydrogen from the mixture into the formation.

1200. The method of claim 1169, further comprising:

providing hydrogen (H2) to the heated section to hydrogenate hydrocarbons within the section; and

heating a portion of the section with heat from hydrogenation.

1201. The method of claim 1169, wherein the produced mixture comprises hydrogen and condensable hydrocarbons, the method further comprising hydrogenating a portion of the produced condensable hydrocarbons with at least a portion of the produced hydrogen.

1202. The method of claim 1169, wherein allowing the heat to transfer comprises increasing a permeability of a majority of the selected section to greater than about 100 millidarcy.

1203. The method of claim 1169, wherein allowing the heat to transfer comprises substantially uniformly increasing a permeability of a majority of the selected section.

1204. The method of claim 1169, further comprising controlling the heat to yield greater than about 60% by weight of condensable hydrocarbons, as measured by Fischer Assay.

1205. The method of claim 1169, wherein producing the mixture comprises producing the mixture in a production well, and wherein at least about 7 heat sources are disposed in the formation for each production well.

1206. The method of claim 1205, wherein at least about 20 heat sources are disposed in the formation for each production well.

1207. The method of claim 1169, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, and wherein the unit of heat sources comprises a triangular pattern.

1208. The method of claim 1169, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, wherein the unit of heat sources comprises a triangular pattern, and wherein a plurality of the units are repeated over an area of the formation to form a repetitive pattern of units.

1209. A method of treating an oil shale formation in situ, comprising:

providing heat from one or more heat sources to at least a portion of the formation;

allowing the heat to transfer from the one or more heat sources to a selected section of the formation; and

producing a mixture from the formation, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is oxygen.

1210. The method of claim 1209, wherein the one or more heat sources comprise at least two heat sources, and wherein superposition of heat from at least the two heat sources pyrolyzes at least some hydrocarbons within the selected section of the formation.

1211. The method of claim 1209, wherein the one or more heat sources comprise electrical heaters.

1212. The method of claim 1209, wherein the one or more heat sources comprise surface burners.

1213. The method of claim 1209, wherein the one or more heat sources comprise flameless distributed combustors.

1214. The method of claim 1209, wherein the one or more heat sources comprise natural distributed combustors.

1215. The method of claim 1209, further comprising controlling a pressure and a temperature within at least a majority of the selected section of the formation, wherein the pressure is controlled as a function of temperature, or the temperature is controlled as a function of pressure.

1216. The method of claim 1215, wherein controlling the temperature comprises maintaining the temperature within the selected section within a pyrolysis temperature range.

1217. The method of claim 1209, further comprising controlling the heat such that an average heating rate of the selected section is less than about 1° C. per day during pyrolysis.

1218. The method of claim 1209, wherein providing heat from the one or more heat sources to at least the portion of formation comprises:

heating a selected volume (V) of the oil shale formation from the one or more heat sources, wherein the formation has an average heat capacity (Cv), and wherein the heating pyrolyzes at least some hydrocarbons within the selected volume of the formation; and

wherein heating energy/day provided to the volume is equal to or less than Pwr, wherein Pwr is calculated by the equation:

Pwr=h*V*Cv*ρB

wherein Pwr is the heating energy/day, h is an average heating rate of the formation, ρB is formation bulk density, and wherein the heating rate is less than about 10° C./day.

1220. The method of claim 1209, wherein providing heat from the one or more heat sources comprises heating the selected section such that a thermal conductivity of at least a portion of the selected section is greater than about 0.5 W/(m° C.).

1221. The method of claim 1209, wherein the produced mixture comprises condensable hydrocarbons having an API gravity of at least about 25°.

1222. The method of claim 1209, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 0.1% by weight to about 15% by weight of the condensable hydrocarbons are olefins.

1223. The method of claim 1209, wherein the produced mixture comprises non-condensable hydrocarbons, and wherein about 0.1% by weight to about 15% by weight of the non-condensable hydrocarbons are olefins.

1224. The method of claim 1209, wherein the produced mixture comprises non-condensable hydrocarbons, wherein a molar ratio of ethene to ethane in the non-condensable hydrocarbons is less than about 0.15, and wherein the ratio of ethene to ethane is greater than about 0.001.

1225. The method of claim 1209, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is nitrogen.

1226. The method of claim 1209, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is oxygen.

1227. The method of claim 1209, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is sulfur.

1228. The method of claim 1209, wherein the produced mixture comprises condensable hydrocarbons, wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons comprise oxygen containing compounds, and wherein the oxygen containing compounds comprise phenols.

1229. The method of claim 1209, wherein the produced mixture comprises condensable hydrocarbons, and wherein greater than about 20% by weight of the condensable hydrocarbons are aromatic compounds.

1230. The method of claim 1209, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 5% by weight of the condensable hydrocarbons comprises multi-ring aromatics with more than two rings.

1231. The method of claim 1209, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 0.3% by weight of the condensable hydrocarbons are asphaltenes.

1232. The method of claim 1209, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons are cycloalkanes.

1233. The method of claim 1209, wherein the produced mixture comprises a non-condensable component, wherein the non-condensable component comprises hydrogen, wherein the hydrogen is greater than about 10% by volume of the non-condensable component, and wherein the hydrogen is less than about 80% by volume of the non-condensable component.

1234. The method of claim 1209, wherein the produced mixture comprises ammonia, and wherein greater than about 0.05% by weight of the produced mixture is ammonia.

1235. The method of claim 1209, wherein the produced mixture comprises ammonia, and wherein the ammonia is used to produce fertilizer.

1236. The method of claim 1209, further comprising controlling a pressure within at least a majority of the selected section of the formation, wherein the controlled pressure is at least about 2.0 bars absolute.

1237. The method of claim 1209, further comprising controlling formation conditions to produce a mixture of condensable hydrocarbons and H2, wherein a partial pressure of H2 within the mixture is greater than about 0.5 bars.

1238. The method of claim 1237, wherein the partial pressure of H2 is measured when the mixture is at a production well.

1239. The method of claim 1209, further comprising altering a pressure within the formation to inhibit production of hydrocarbons from the formation having carbon numbers greater than about 25.

1240. The method of claim 1209, wherein controlling formation conditions comprises recirculating a portion of hydrogen from the mixture into the formation.

1241. The method of claim 1209, further comprising:

providing hydrogen (H2) to the heated section to hydrogenate hydrocarbons within the section; and

heating a portion of the section with heat from hydrogenation.

1242. The method of claim 1209, wherein the produced mixture comprises hydrogen and condensable hydrocarbons, the method further comprising hydrogenating a portion of the produced condensable hydrocarbons with at least a portion of the produced hydrogen.

1243. The method of claim 1209, wherein allowing the heat to transfer comprises increasing a permeability of a majority of the selected section to greater than about 100 millidarcy.

1244. The method of claim 1209, wherein allowing the heat to transfer comprises substantially uniformly increasing a permeability of a majority of the selected section.

1245. The method of claim 1209, further comprising controlling the heat to yield greater than about 60% by weight of condensable hydrocarbons, as measured by Fischer Assay.

1246. The method of claim 1209, wherein producing the mixture comprises producing the mixture in a production well, and wherein at least about 7 heat sources are disposed in the formation for each production well.

1247. The method of claim 1246, wherein at least about 20 heat sources are disposed in the formation for each production well.

1248. The method of claim 1209, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, and wherein the unit of heat sources comprises a triangular pattern.

1249. The method of claim 1209, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, wherein the unit of heat sources comprises a triangular pattern, and wherein a plurality of the units are repeated over an area of the formation to form a repetitive pattern of units.

1250. A method of treating an oil shale formation in situ, comprising:

providing heat from one or more heat sources to at least a portion of the formation;

allowing the heat to transfer from the one or more heat sources to a selected section of the formation; and

producing a mixture from the formation, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is sulfur.

1251. The method of claim 1250, wherein the one or more heat sources comprise at least two heat sources, and wherein superposition of heat from at least the two heat sources pyrolyzes at least some hydrocarbons within the selected section of the formation.

1252. The method of claim 1250, wherein the one or more heat sources comprise electrical heaters.

1253. The method of claim 1250, wherein the one or more heat sources comprise surface burners.

1254. The method of claim 1250, wherein the one or more heat sources comprise flameless distributed combustors.

1255. The method of claim 1250, wherein the one or more heat sources comprise natural distributed combustors.

1256. The method of claim 1250, further comprising controlling a pressure and a temperature within at least a majority of the selected section of the formation, wherein the pressure is controlled as a function of temperature, or the temperature is controlled as a function of pressure.

1257. The method of claim 1256, wherein controlling the temperature comprises maintaining the temperature within the selected section within a pyrolysis temperature range.

1258. The method of claim 1250, further comprising controlling the heat such that an average heating rate of the selected section is less than about 1° C. per day during pyrolysis.

1259. The method of claim 1250, wherein providing heat from the one or more heat sources to at least the portion of formation comprises:

heating a selected volume (V) of the oil shale formation from the one or more heat sources, wherein the formation has an average heat capacity (Cv), and wherein the heating pyrolyzes at least some hydrocarbons within the selected volume of the formation; and

wherein heating energy/day provided to the volume is equal to or less than Pwr, wherein Pwr is calculated by the equation:

Pwr=h*V*Cv*ρB

wherein Pwr is the heating energy/day, h is an average heating rate of the formation, ρB is formation bulk density, and wherein the heating rate is less than about 10° C./day.

1261. The method of claim 1250, wherein providing heat from the one or more heat sources comprises heating the selected formation such that a thermal conductivity of at least a portion of the selected section is greater than about 0.5 W/(m° C.).

1262. The method of claim 1250, wherein the produced mixture comprises condensable hydrocarbons having an API gravity of at least about 25°.

1263. The method of claim 1250, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 0.1% by weight to about 15% by weight of the condensable hydrocarbons are olefins.

1264. The method of claim 1250, wherein the produced mixture comprises non-condensable hydrocarbons, and wherein about 0.1% by weight to about 15% by weight of the non-condensable hydrocarbons are olefins.

1265. The method of claim 1250, wherein the produced mixture comprises non-condensable hydrocarbons, wherein a molar ratio of ethene to ethane in the non-condensable hydrocarbons is less than about 0.15, and wherein the ratio of ethene to ethane is greater than about 0.001.

1266. The method of claim 1250, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is nitrogen.

1267. The method of claim 1250, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is oxygen.

1268. The method of claim 1250, wherein the produced mixture comprises condensable hydrocarbons, wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons comprise oxygen containing compounds, and wherein the oxygen containing compounds comprise phenols.

1269. The method of claim 1250, wherein the produced mixture comprises condensable hydrocarbons, and wherein greater than about 20% by weight of the condensable hydrocarbons are aromatic compounds.

1270. The method of claim 1250, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 5% by weight of the condensable hydrocarbons comprises multi-ring aromatics with more than two rings.

1271. The method of claim 1250, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 0.3% by weight of the condensable hydrocarbons are asphaltenes.

1272. The method of claim 1250, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons are cycloalkanes.

1273. The method of claim 1250, wherein the produced mixture comprises a non-condensable component, wherein the non-condensable component comprises hydrogen, wherein the hydrogen is greater than about 10% by volume of the non-condensable component, and wherein the hydrogen is less than about 80% by volume of the non-condensable component.

1274. The method of claim 1250, wherein the produced mixture comprises ammonia, and wherein greater than about 0.05% by weight of the produced mixture is ammonia.

1275. The method of claim 1250, wherein the produced mixture comprises ammonia, and wherein the ammonia is used to produce fertilizer.

1276. The method of claim 1250, further comprising controlling a pressure within at least a majority of the selected section of the formation, wherein the controlled pressure is at least about 2.0 bars absolute.

1277. The method of claim 1250, further comprising controlling formation conditions to produce a mixture of condensable hydrocarbons and H2, wherein a partial pressure of H2 within the mixture is greater than about 0.5 bars.

1278. The method of claim 1277, wherein the partial pressure of H2 is measured when the mixture is at a production well.

1279. The method of claim 1250, further comprising altering a pressure within the formation to inhibit production of hydrocarbons from the formation having carbon numbers greater than about 25.

1280. The method of claim 1250, wherein controlling formation conditions comprises recirculating a portion of hydrogen from the mixture into the formation.

1281. The method of claim 1250, further comprising:

providing hydrogen (H2) to the heated section to hydrogenate hydrocarbons within the section; and

heating a portion of the section with heat from hydrogenation.

1282. The method of claim 1250, wherein the produced mixture comprises hydrogen and condensable hydrocarbons, the method further comprising hydrogenating a portion of the produced condensable hydrocarbons with at least a portion of the produced hydrogen.

1283. The method of claim 1250, wherein allowing the heat to transfer comprises increasing a permeability of a majority of the selected section to greater than about 100 millidarcy.

1284. The method of claim 1250, wherein allowing the heat to transfer comprises substantially uniformly increasing a permeability of a majority of the selected section.

1285. The method of claim 1250, further comprising controlling the heat to yield greater than about 60% by weight of condensable hydrocarbons, as measured by Fischer Assay.

1286. The method of claim 1250, wherein producing the mixture comprises producing the mixture in a production well, and wherein at least about 7 heat sources are disposed in the formation for each production well.

1287. The method of claim 1286, wherein at least about 20 heat sources are disposed in the formation for each production well.

1288. The method of claim 1250, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, and wherein the unit of heat sources comprises a triangular pattern.

1289. The method of claim 1250, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, wherein the unit of heat sources comprises a triangular pattern, and wherein a plurality of the units are repeated over an area of the formation to form a repetitive pattern of units.

1290. A method of treating an oil shale formation in situ, comprising:

raising a temperature of a first section of the formation with one or more heat sources to a first pyrolysis temperature;

heating the first section to an upper pyrolysis temperature, wherein heat is supplied to the first section at a rate configured to inhibit olefin production;

producing a first mixture from the formation, wherein the first mixture comprises condensable hydrocarbons and H2;

creating a second mixture from the first mixture, wherein the second mixture comprises a higher concentration of H2 than the first mixture;

raising a temperature of a second section of the formation with one or more heat sources to a second pyrolysis temperature;

providing a portion of the second mixture to the second section;

heating the second section to an upper pyrolysis temperature, wherein heat is supplied to the second section at a rate configured to inhibit olefin production; and

producing a third mixture from the second section.

1291. The method of claim 1290, wherein creating the second mixture comprises removing condensable hydrocarbons from the first mixture.

1292. The method of claim 1290, wherein creating the second mixture comprises removing water from the first mixture.

1293. The method of claim 1290, wherein creating the second mixture comprises removing carbon dioxide from the first mixture.

1294. The method of claim 1290, wherein the first pyrolysis temperature is greater than about 270° C.

1295. The method of claim 1290, wherein the second pyrolysis temperature is greater than about 270° C.

1296. The method of claim 1290, wherein the upper pyrolysis temperature is about 500° C.

1297. The method of claim 1290, wherein the one or more heat sources comprise at least two heat sources, and wherein superposition of heat from at least the two heat sources pyrolyzes at least some hydrocarbons within the first or second selected section of the formation.

1298. The method of claim 1290, wherein the one or more heat sources comprise electrical heaters.

1299. The method of claim 1290, wherein the one or more heat sources comprise surface burners.

1300. The method of claim 1290, wherein the one or more heat sources comprise flameless distributed combustors.

1301. The method of claim 1290, wherein the one or more heat sources comprise natural distributed combustors.

1302. The method of claim 1290, further comprising controlling a pressure and a temperature within at least a majority of the first section and the second section of the formation, wherein the pressure is controlled as a function of temperature, or the temperature is controlled as a function of pressure.

1303. The method of claim 1290, further comprising controlling the heat to the first and second sections such that an average heating rate of the first and second sections is less than about 1° C. per day during pyrolysis.

1304. The method of claim 1290, wherein heating the first and the second sections comprises:

heating a selected volume (V) of the oil shale formation from the one or more heat sources, wherein the formation has an average heat capacity (Cv), and wherein the heating pyrolyzes at least some hydrocarbons within the selected volume of the formation; and

wherein heating energy/day provided to the volume is equal to or less than Pwr, wherein Pwr is calculated by the equation:

Pwr=h*V*Cv*ρB

wherein Pwr is the heating energy/day, h is an average heating rate of the formation, ρB is formation bulk density, and wherein the heating rate is less than about 10° C./day.

1305. The method of claim 1290, wherein heating the first and second sections comprises transferring heat substantially by conduction.

1306. The method of claim 1290, wherein heating the first and second sections comprises heating the first and second sections such that a thermal conductivity of at least a portion of the first and second sections is greater than about 0.5 W/(m ° C.).

1307. The method of claim 1290, wherein the first or third mixture comprises condensable hydrocarbons having an API gravity of at least about 25°.

1308. The method of claim 1290, wherein the first or third mixture comprises condensable hydrocarbons, and wherein about 0.1% by weight to about 15% by weight of the condensable hydrocarbons are olefins.

1309. The method of claim 1290, wherein the first or third mixture comprises non-condensable hydrocarbons, and wherein a molar ratio of ethene to ethane in the non-condensable hydrocarbons ranges from about 0.001 to about 0.15.

1310. The method of claim 1290, wherein the first or third mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is nitrogen.

1311. The method of claim 1290, wherein the first or third mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is oxygen.

1312. The method of claim 1290, wherein the first or third mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is sulfur.

1313. The method of claim 1290, wherein the first or third mixture comprises condensable hydrocarbons, wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons comprise oxygen containing compounds, and wherein the oxygen containing compounds comprise phenols.

1314. The method of claim 1290, wherein the first or third mixture comprises condensable hydrocarbons, and wherein greater than about 20% by weight of the condensable hydrocarbons are aromatic compounds.

1315. The method of claim 1290, wherein the first or third mixture comprises condensable hydrocarbons, and wherein less than about 5% by weight of the condensable hydrocarbons comprises multi-ring aromatics with more than two rings.

1316. The method of claim 1290, wherein the first or third mixture comprises condensable hydrocarbons, and wherein less than about 0.3% by weight of the condensable hydrocarbons are asphaltenes.

1317. The method of claim 1290, wherein the first or third mixture comprises condensable hydrocarbons, and wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons are cycloalkanes.

1318. The method of claim 1290, wherein the first or third mixture comprises anon-condensable component, and wherein the non-condensable component comprises hydrogen, and wherein the hydrogen is greater than about 10% by volume of the non-condensable component and wherein the hydrogen is less than about 80% by volume of the non-condensable component.

1319. The method of claim 1290, wherein the first or third mixture comprises ammonia, and wherein greater than about 0.05% by weight of the produced mixture is ammonia.

1320. The method of claim 1290, wherein the first or third mixture comprises ammonia, and wherein the ammonia is used to produce fertilizer.

1321. The method of claim 1290, further comprising controlling a pressure within at least a majority of the first or second sections of the formation, wherein the controlled pressure is at least about 2.0 bars absolute.

1322. The method of claim 1290, further comprising controlling formation conditions to produce a mixture of condensable hydrocarbons and H2, wherein a partial pressure of H2 within the mixture is greater than about 0.5 bars.

1323. The method of claim 1322, wherein the partial pressure of H2 within a mixture is measured when the mixture is at a production well.

1324. The method of claim 1290, further comprising altering a pressure within the formation to inhibit production of hydrocarbons from the formation having carbon numbers greater than about 25.

1325. The method of claim 1290, further comprising:

providing hydrogen (H2) to the first or second section to hydrogenate hydrocarbons within the first or second section; and

heating a portion of the first or second section with heat from hydrogenation.

1326. The method of claim 1290, further comprising:

producing hydrogen and condensable hydrocarbons from the formation; and

hydrogenating a portion of the produced condensable hydrocarbons with at least a portion of the produced hydrogen.

1327. The method of claim 1290, further comprising increasing a permeability of a majority of the first or second section to greater than about 100 millidarcy.

1328. The method of claim 1290, further comprising substantially uniformly increasing a permeability of a majority of the first or second section.

1329. The method of claim 1290, wherein the heating is controlled to yield greater than about 60% by weight of condensable hydrocarbons, as measured by Fischer Assay.

1330. The method of claim 1290, wherein producing the first or third mixture comprises producing the first or third mixture in a production well, and wherein at least about 7 heat sources are disposed in the formation for each production well.

1331. The method of claim 1330, wherein at least about 20 heat sources are disposed in the formation for each production well.

1332. The method of claim 1290, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, and wherein the unit of heat sources comprises a triangular pattern.

1333. The method of claim 1290, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, wherein the unit of heat sources comprises a triangular pattern, and wherein a plurality of the units are repeated over an area of the formation to form a repetitive pattern of units.

1334. A method of treating an oil shale formation in situ, comprising: providing heat from one or more heat sources to at least a portion of the formation;

allowing the heat to transfer from the one or more heat sources to a selected section of the formation;

producing a mixture from the formation; and

hydrogenating a portion of the produced mixture with H2 produced from the formation.

1335. The method of claim 1334, wherein the one or more heat sources comprise at least two heat sources, and wherein superposition of heat from at least the two heat sources pyrolyzes at least some hydrocarbons within the selected section of the formation.

1336. The method of claim 1334, further comprising maintaining a temperature within the selected section within a pyrolysis temperature range.

1337. The method of claim 1334, wherein the one or more heat sources comprise electrical heaters.

1338. The method of claim 1334, wherein the one or more heat sources comprise surface burners.

1339. The method of claim 1334, wherein the one or more heat sources comprise flameless distributed combustors.

1340. The method of claim 1334, wherein the one or more heat sources comprise natural distributed combustors.

1341. The method of claim 1334, further comprising controlling a pressure and a temperature within at least a majority of the selected section of the formation, wherein the pressure is controlled as a function of temperature, or the temperature is controlled as a function of pressure.

1342. The method of claim 1334, further comprising controlling the heat such that an average heating rate of the selected section is less than about 1° C. per day during pyrolysis.

1343. The method of claim 1334, wherein providing heat from the one or more heat sources to at least the portion of formation comprises:

heating a selected volume (V) of the oil shale formation from the one or more heat sources, wherein the formation has an average heat capacity (Cv), and wherein the heating pyrolyzes at least some hydrocarbons within the selected volume of the formation; and

wherein heating energy/day provided to the volume is equal to or less than Pwr, wherein Pwr is calculated by the equation:

Pwr=h*V*Cv*ρB

wherein Pwr is the heating energy/day, h is an average heating rate of the formation, ρB is formation bulk density, and wherein the heating rate is less than about 10° C./day.

1345. The method of claim 1334, wherein providing heat from the one or more heat sources comprises heating the selected section such that a thermal conductivity of at least a portion of the selected section is greater than about 0.5 W/(m ° C.).

1346. The method of claim 1334, wherein the produced mixture comprises condensable hydrocarbons having an API gravity of at least about 25°.

1347. The method of claim 1334, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 0.1% by weight to about 15% by weight of the condensable hydrocarbons are olefins.

1348. The method of claim 1334, wherein the produced mixture comprises non-condensable hydrocarbons, and wherein a molar ratio of ethene to ethane in the non-condensable hydrocarbons ranges from about 0.001 to about 0.15.

1349. The method of claim 1334, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is nitrogen.

1350. The method of claim 1334, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is oxygen.

1351. The method of claim 1334, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is sulfur.

1352. The method of claim 1334, wherein the produced mixture comprises condensable hydrocarbons, wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons comprise oxygen containing compounds, and wherein the oxygen containing compounds comprise phenols.

1353. The method of claim 1334, wherein the produced mixture comprises condensable hydrocarbons, and wherein greater than about 20% by weight of the condensable hydrocarbons are aromatic compounds.

1354. The method of claim 1334, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 5% by weight of the condensable hydrocarbons comprises multi-ring aromatics with more than two rings.

1355. The method of claim 1334, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 0.3% by weight of the condensable hydrocarbons are asphaltenes.

1356. The method of claim 1334, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons are cycloalkanes.

1357. The method of claim 1334, wherein the produced mixture comprises anon-condensable component, wherein the non-condensable component comprises hydrogen, wherein the hydrogen is greater than about 10% by volume of the non-condensable component, and wherein the hydrogen is less than about 80% by volume of the non-condensable component.

1358. The method of claim 1334, wherein the produced mixture comprises ammonia, and wherein greater than about 0.05% by weight of the produced mixture is ammonia.

1359. The method of claim 1334, wherein the produced mixture comprises ammonia, and wherein the ammonia is used to produce fertilizer.

1360. The method of claim 1334, further comprising controlling a pressure within at least a majority of the selected section of the formation, wherein the controlled pressure is at least about 2.0 bars absolute.

1361. The method of claim 1334, further comprising controlling formation conditions to produce the mixture, wherein a partial pressure of H2 within the mixture is greater than about 0.5 bars.

1362. The method of claim 1334, wherein a partial pressure of H2 within the mixture is measured when the mixture is at a production well.

1363. The method of claim 1334, further comprising altering a pressure within the formation to inhibit production of hydrocarbons from the formation having carbon numbers greater than about 25.

1364. The method of claim 1334, further comprising:

providing hydrogen (H2) to the heated section to hydrogenate hydrocarbons within the section; and

heating a portion of the section with heat from hydrogenation.

1365. The method of claim 1334, wherein allowing the heat to transfer comprises increasing a permeability of a majority of the selected section to greater than about 100 millidarcy.

1366. The method of claim 1334, wherein allowing the heat to transfer comprises substantially uniformly increasing a permeability of a majority of the selected section.

1367. The method of claim 1334, further comprising controlling the heat to yield greater than about 60% by weight of condensable hydrocarbons, as measured by Fischer Assay.

1368. The method of claim 1334, wherein producing the mixture comprises producing the mixture in a production well, and wherein at least about 7 heat sources are disposed in the formation for each production well.

1369. The method of claim 1368, wherein at least about 20 heat sources are disposed in the formation for each production well.

1370. The method of claim 1334, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, and wherein the unit of heat sources comprises a triangular pattern.

1371. The method of claim 1334, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, wherein the unit of heat sources comprises a triangular pattern, and wherein a plurality of the units are repeated over an area of the formation to form a repetitive pattern of units.

1372. A method of treating an oil shale formation in situ, comprising:

heating a first section of the formation;

producing H2 from the first section of formation;

heating a second section of the formation; and

recirculating a portion of the H2 from the first section into the second section of the formation to provide a reducing environment within the second section of the formation.

1373. The method of claim 1372, wherein heating the first section or heating the second section comprises heating with an electrical heater.

1374. The method of claim 1372, wherein heating the first section or heating the second section comprises heating with a surface burner.

1375. The method of claim 1372, wherein heating the first section or heating the second section comprises heating with a flameless distributed combustor.

1376. The method of claim 1372, wherein heating the first section or heating the second section comprises heating with a natural distributed combustor.

1377. The method of claim 1372, further comprising controlling a pressure and a temperature within at least a majority of the first or second section of the formation, wherein the pressure is controlled as a function of temperature, or the temperature is controlled as a function of pressure.

1378. The method of claim 1372, further comprising controlling the heat such that an average heating rate of the first or second section is less than about 1° C. per day during pyrolysis.

1379. The method of claim 1372, wherein heating the first section or heating the second section further comprises:

heating a selected volume (V) of the oil shale formation from the one or more heat sources, wherein the formation has an average heat capacity (Cv), and wherein the heating pyrolyzes at least some hydrocarbons within the selected volume of the formation; and

wherein heating energy/day provided to the volume is equal to or less than Pwr, wherein Pwr is calculated by the equation:

Pwr=h*V*Cv*ρB

wherein Pwr is the heating energy/day, h is an average heating rate of the formation, ρB is formation bulk density, and wherein the heating rate is less than about 10° C./day.

1380. The method of claim 1372, wherein heating the first section or heating the second section comprises transferring heat substantially by conduction.

1381. The method of claim 1372, wherein heating the first section or heating the second section comprises heating the formation such that a thermal conductivity of at least a portion of the first or second section is greater than about 0.5 W/(m ° C.).

1382. The method of claim 1372, further comprising producing a mixture from the second section, wherein the produced mixture comprises condensable hydrocarbons having an API gravity of at least about 25°.

1383. The method of claim 1372, further comprising producing a mixture from the second section, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 0.1% by weight to about 15% by weight of the condensable hydrocarbons are olefins.

1384. The method of claim 1372, further comprising producing a mixture from the second section, wherein the produced mixture comprises non-condensable hydrocarbons, and wherein a molar ratio of ethene to ethane in the non-condensable hydrocarbons ranges from about 0.001 to about 0.15.

1385. The method of claim 1372, further comprising producing a mixture from the second section, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is nitrogen.

1386. The method of claim 1372, further comprising producing a mixture from the second section, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is oxygen.

1387. The method of claim 1372, further comprising producing a mixture from the second section, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is sulfur.

1388. The method of claim 1372, further comprising producing a mixture from the second section, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons comprise oxygen containing compounds, and wherein the oxygen containing compounds comprise phenols.

1389. The method of claim 1372, further comprising producing a mixture from the second section, wherein the produced mixture comprises condensable hydrocarbons, and wherein greater than about 20% by weight of the condensable hydrocarbons are aromatic compounds.

1390. The method of claim 1372, further comprising producing a mixture from the second section, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 5% by weight of the condensable hydrocarbons comprises multi-ring aromatics with more than two rings.

1391. The method of claim 1372, further comprising producing a mixture from the second section, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 0.3% by weight of the condensable hydrocarbons are asphaltenes.

1392. The method of claim 1372, further comprising producing a mixture from the second section, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons are cycloalkanes.

1393. The method of claim 1372, further comprising producing a mixture from the second section, wherein the produced mixture comprises a non-condensable component, wherein the non-condensable component comprises hydrogen, wherein the hydrogen is greater than about 10% by volume of the non-condensable component, and wherein the hydrogen is less than about 80% by volume of the non-condensable component.

1394. The method of claim 1372, further comprising producing a mixture from the second section, wherein the produced mixture comprises ammonia, and wherein greater than about 0.05% by weight of the produced mixture is ammonia.

1395. The method of claim 1372, further comprising producing a mixture from the second section, wherein the produced mixture comprises ammonia, and wherein the ammonia is used to produce fertilizer.

1396. The method of claim 1372, further comprising controlling a pressure within at least a majority of the first or second section of the formation, wherein the controlled pressure is at least about 2.0 bars absolute.

1397. The method of claim 1372, further comprising controlling formation conditions to produce a mixture of condensable hydrocarbons and H2, wherein a partial pressure of H2 within the mixture is greater than about 0.5 bars.

1398. The method of claim 1397, wherein the partial pressure of H2 within a mixture is measured when the mixture is at a production well.

1399. The method of claim 1372, further comprising altering a pressure within the formation to inhibit production of hydrocarbons from the formation having carbon numbers greater than about 25.

1400. The method of claim 1372, further comprising:

providing hydrogen (H2) to the second section to hydrogenate hydrocarbons within the section; and

heating a portion of the second section with heat from hydrogenation.

1401. The method of claim 1372, further comprising:

producing hydrogen and condensable hydrocarbons from the formation; and

hydrogenating a portion of the produced condensable hydrocarbons with at least a portion of the produced hydrogen.

1402. The method of claim 1372, wherein heating the first section or heating the second section comprises increasing a permeability of a majority of the first or second section, respectively, to greater than about 100 millidarcy.

1403. The method of claim 1372, wherein heating the first section or heating the second section comprises substantially uniformly increasing a permeability of a majority of the first or second section, respectively.

1404. The method of claim 1372, further comprising controlling the heating of the first section or controlling the heat of the second section to yield greater than about 60% by weight of condensable hydrocarbons, as measured by Fischer Assay.

1405. The method of claim 1372, further comprising producing a mixture from the formation in a production well, and wherein at least about 7 heat sources are disposed in the formation for each production well.

1406. The method of claim 1405, wherein at least about 20 heat sources are disposed in the formation for each production well.

1407. The method of claim 1372, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, and wherein the unit of heat sources comprises a triangular pattern.

1408. The method of claim 1372, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, wherein the unit of heat sources comprises a triangular pattern, and wherein a plurality of the units are repeated over an area of the formation to form a repetitive pattern of units.

1409. A method of treating an oil shale formation in situ, comprising:

providing heat from one or more heat sources to at least a portion of the formation;

allowing the heat to transfer from the one or more heat sources to a selected section of the formation;

producing a mixture from the formation; and

controlling formation conditions such that the mixture produced from the formation comprises condensable hydrocarbons including H2, wherein a partial pressure of H2 within the mixture is greater than about 0.5 bars.

1410. The method of claim 1409, wherein the one or more heat sources comprise at least two heat sources, and wherein superposition of heat from at least the two heat sources pyrolyzes at least some hydrocarbons within the selected section of the formation.

1411. The method of claim 1409, wherein controlling formation conditions comprises maintaining a temperature within the selected section within a pyrolysis temperature range.

1412. The method of claim 1409, wherein the one or more heat sources comprise electrical heaters.

1413. The method of claim 1409, wherein the one or more heat sources comprise surface burners.

1414. The method of claim 1409, wherein the one or more heat sources comprise flameless distributed combustors.

1415. The method of claim 1409, wherein the one or more heat sources comprise natural distributed combustors.

1416. The method of claim 1409, further comprising controlling a pressure and a temperature within at least a majority of the selected section of the formation, wherein the pressure is controlled as a function of temperature, or the temperature is controlled as a function of pressure.

1417. The method of claim 1409, further comprising controlling the heat such that an average heating rate of the selected section is less than about 1° C. per day during pyrolysis.

1418. The method of claim 1409, wherein providing heat from the one or more heat sources to at least the portion of formation comprises:

heating a selected volume (V) of the oil shale formation from the one or more heat sources, wherein the formation has an average heat capacity (Cv), and wherein the heating pyrolyzes at least some hydrocarbons within the selected volume of the formation; and

wherein heating energy/day provided to the volume is equal to or less than Pwr, wherein Pwr is calculated by the equation:

Pwr=h*V*Cv*ρB

wherein Pwr is the heating energy/day, h is an average heating rate of the formation, ρB is formation bulk density, and wherein the heating rate is less than about 10° C./day.

1420. The method of claim 1409, wherein providing heat from the one or more heat sources comprises heating the selected section such that a thermal conductivity of at least a portion of the selected section is greater than about 0.5 W/(m ° C.).

1421. The method of claim 1409, wherein the produced mixture comprises condensable hydrocarbons having an API gravity of at least about 25°.

1422. The method of claim 1409, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 0.1% by weight to about 15% by weight of the condensable hydrocarbons are olefins.

1423. The method of claim 1409, wherein the produced mixture comprises non-condensable hydrocarbons, and wherein a molar ratio of ethene to ethane in the non-condensable hydrocarbons ranges from about 0.001 to about 0.15.

1424. The method of claim 1409, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is nitrogen.

1425. The method of claim 1409, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is oxygen.

1426. The method of claim 1409, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is sulfur.

1427. The method of claim 1409, wherein the produced mixture comprises condensable hydrocarbons, wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons comprise oxygen containing compounds, and wherein the oxygen containing compounds comprise phenols.

1428. The method of claim 1409, wherein the produced mixture comprises condensable hydrocarbons, and wherein greater than about 20% by weight of the condensable hydrocarbons are aromatic compounds.

1429. The method of claim 1409, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 5% by weight of the condensable hydrocarbons comprises multi-ring aromatics with more than two rings.

1430. The method of claim 1409, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 0.3% by weight of the condensable hydrocarbons are asphaltenes.

1431. The method of claim 1409, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons are cycloalkanes.

1432. The method of claim 1409, wherein the produced mixture comprises a non-condensable component, wherein the non-condensable component comprises hydrogen, wherein the hydrogen is greater than about 10% by volume of the non-condensable component, and wherein the hydrogen is less than about 80% by volume of the non-condensable component.

1433. The method of claim 1409, wherein the produced mixture comprises ammonia, and wherein greater than about 0.05% by weight of the produced mixture is ammonia.

1434. The method of claim 1409, wherein the produced mixture comprises ammonia, and wherein the ammonia is used to produce fertilizer.

1435. The method of claim 1409, further comprising controlling a pressure within at least a majority of the selected section of the formation, wherein the controlled pressure is at least about 2.0 bars absolute.

1436. The method of claim 1409, further comprising altering a pressure within the formation to inhibit production of hydrocarbons from the formation having carbon numbers greater than about 25.

1437. The method of claim 1409, wherein controlling formation conditions comprises recirculating a portion of hydrogen from the mixture into the formation.

1438. The method of claim 1409, further comprising:

providing hydrogen (H2) to the heated section to hydrogenate hydrocarbons within the section; and

heating a portion of the section with heat from hydrogenation.

1439. The method of claim 1409, further comprising:

producing hydrogen and condensable hydrocarbons from the formation; and

hydrogenating a portion of the produced condensable hydrocarbons with at least a portion of the produced hydrogen.

1440. The method of claim 1409, wherein allowing the heat to transfer comprises increasing a permeability of a majority of the selected section to greater than about 100 millidarcy.

1441. The method of claim 1409, wherein allowing the heat to transfer comprises substantially uniformly increasing a permeability of a majority of the selected section.

1442. The method of claim 1409, further comprising controlling the heat to yield greater than about 60% by weight of condensable hydrocarbons, as measured by Fischer Assay.

1443. The method of claim 1409, wherein producing the mixture comprises producing its the mixture in a production well, and wherein at least about 7 heat sources are disposed in the formation for each production well.

1444. The method of claim 1443, wherein at least about 20 heat sources are disposed in the formation for each production well.

1445. The method of claim 1409, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, and wherein the unit of heat sources comprises a triangular pattern.

1446. The method of claim 1409, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, wherein the unit of heat sources comprises a triangular pattern, and wherein a plurality of the units are repeated over an area of the formation to form a repetitive pattern of units.

1447. The method of claim 1409, wherein a partial pressure of H2 within the mixture is measured when the mixture is at a production well.

1448. A method of treating an oil shale formation in situ, comprising:

providing heat from one or more heat sources to at least a portion of the formation;

allowing the heat to transfer from the one or more heat sources to a selected section of the formation;

maintaining a pressure of the selected section above atmospheric pressure to increase a partial pressure of H2, as compared to the partial pressure of H2 at atmospheric pressure, in at least a majority of the selected section; and

producing a mixture from the formation, wherein the produced mixture comprises condensable hydrocarbons having an API gravity of at least about 25°.

1449. The method of claim 1448, wherein the one or more heat sources comprise at least two heat sources, and wherein superposition of heat from at least the two heat sources pyrolyzes at least some hydrocarbons within the selected section of the formation.

1450. The method of claim 1448, further comprising maintaining a temperature within the selected section within a pyrolysis temperature range.

1451. The method of claim 1448, wherein the one or more heat sources comprise electrical heaters.

1452. The method of claim 1448, wherein the one or more heat sources comprise surface burners.

1453. The method of claim 1448, wherein the one or more heat sources comprise flameless distributed combustors.

1454. The method of claim 1448, wherein the one or more heat sources comprise natural distributed combustors.

1455. The method of claim 1448, further comprising controlling the pressure and a temperature within at least a majority of the selected section of the formation, wherein the pressure is controlled as a function of temperature, or the temperature is controlled as a function of pressure.

1456. The method of claim 1448, further comprising controlling the heat such that an average heating rate of the selected section is less than about 1° C. per day during pyrolysis.

1457. The method of claim 1448, wherein providing heat from the one or more heat sources to at least the portion of formation comprises:

heating a selected volume (V) of the oil shale formation from the one or more heat sources, wherein the formation has an average heat capacity (Cv), and wherein the heating pyrolyzes at least some hydrocarbons within the selected volume of the formation; and

wherein heating energy/day provided to the volume is equal to or less than Pwr, wherein Pwr is calculated by the equation:

Pwr=h*V*Cv*ρB

wherein Pwr is the heating energy/day, h is an average heating rate of the formation, ρB is formation bulk density, and wherein the heating rate is less than about 10° C./day.

1459. The method of claim 1448, wherein providing heat from the one or more heat sources comprises heating the selected section such that a thermal conductivity of at least a portion of the selected section is greater than about 0.5 W/(m ° C.).

1460. The method of claim 1448, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 0.1% by weight to about 15% by weight of the condensable hydrocarbons are olefins.

1461. The method of claim 1448, wherein the produced mixture comprises non-condensable hydrocarbons, and wherein a molar ratio of ethene to ethane in the non-condensable hydrocarbons ranges from about 0.001 to about 0.15.

1462. The method of claim 1448, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is nitrogen.

1463. The method of claim 1448, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is oxygen.

1464. The method of claim 1448, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is sulfur.

1465. The method of claim 1448, wherein the produced mixture comprises condensable hydrocarbons, wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons comprise oxygen containing compounds, and wherein the oxygen containing compounds comprise phenols.

1466. The method of claim 1448, wherein the produced mixture comprises condensable hydrocarbons, and wherein greater than about 20% by weight of the condensable hydrocarbons are aromatic compounds.

1467. The method of claim 1448, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 5% by weight of the condensable hydrocarbons comprises multi-ring aromatics with more than two rings.

1468. The method of claim 1448, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 0.3% by weight of the condensable hydrocarbons are asphaltenes.

1469. The method of claim 1448, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons are cycloalkanes.

1470. The method of claim 1448, wherein the produced mixture comprises a non-condensable component, wherein the non-condensable component comprises hydrogen, wherein the hydrogen is greater than about 10% by volume of the non-condensable component, and wherein the hydrogen is less than about 80% by volume of the non-condensable component.

1471. The method of claim 1448, wherein the produced mixture comprises ammonia, and wherein greater than about 0.05% by weight of the produced mixture is ammonia.

1472. The method of claim 1448, wherein the produced mixture comprises ammonia, and wherein the ammonia is used to produce fertilizer.

1473. The method of claim 1448, further comprising controlling the pressure within at least a majority of the selected section of the formation, wherein the controlled pressure is at least about 2.0 bars absolute.

1474. The method of claim 1448, further comprising increasing the pressure of the selected section, to an upper limit of about 21 bars absolute, to increase an amount of non-condensable hydrocarbons produced from the formation.

1475. The method of claim 1448, further comprising decreasing pressure of the selected section, to a lower limit of about atmospheric pressure, to increase an amount of condensable hydrocarbons produced from the formation.

1476. The method of claim 1448, wherein a partial pressure comprises a partial pressure based on properties measured at a production well.

1477. The method of claim 1448, further comprising altering the pressure within the to formation to inhibit production of hydrocarbons from the formation having carbon numbers greater than about 25.

1478. The method of claim 1448, further comprising controlling formation conditions by recirculating a portion of hydrogen from the mixture into the formation.

1479. The method of claim 1448, further comprising:

providing hydrogen (H2) to the heated section to hydrogenate hydrocarbons within the section; and

heating a portion of the section with heat from hydrogenation.

1480. The method of claim 1448, further comprising:

producing hydrogen and condensable hydrocarbons from the formation; and

hydrogenating a portion of the produced condensable hydrocarbons with at least a portion of the produced hydrogen.

1481. The method of claim 1448, wherein allowing the heat to transfer comprises increasing a permeability of a majority of the selected section to greater than about 100 millidarcy.

1482. The method of claim 1448, wherein allowing the heat to transfer comprises substantially uniformly increasing a permeability of a majority of the selected section.

1483. The method of claim 1448, further comprising controlling the heat to yield greater than about 60% by weight of condensable hydrocarbons, as measured by Fischer Assay.

1484. The method of claim 1448, wherein producing the mixture comprises producing the mixture in a production well, and wherein at least about 7 heat sources are disposed in the formation for each production well.

1485. The method of claim 1484, wherein at least about 20 heat sources are disposed in the formation for each production well.

1486. The method of claim 1448, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, and wherein the unit of heat sources comprises a triangular pattern.

1487. The method of claim 1448, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, wherein the unit of heat sources comprises a triangular pattern, and wherein a plurality of the units are repeated over an area of the formation to form a repetitive pattern of units.

1488. A method of treating an oil shale formation in situ, comprising:

providing heat from one or more heat sources to at least a portion of the formation;

allowing the heat to transfer from the one or more heat sources to a selected section of the formation;

providing H2 to the formation to produce a reducing environment in at least some of the formation;

producing a mixture from the formation.

1489. The method of claim 1488, wherein the one or more heat sources comprise at least two heat sources, and wherein superposition of heat from at least the two heat sources pyrolyzes at least some hydrocarbons within the selected section of the formation.

1490. The method of claim 1488, further comprising maintaining a temperature within the selected section within a pyrolysis temperature range.

1491. The method of claim 1488, further comprising separating a portion of hydrogen within the mixture and recirculating the portion into the formation.

1492. The method of claim 1488, wherein the one or more heat sources comprise electrical heaters.

1493. The method of claim 1488, wherein the one or more heat sources comprise surface burners.

1494. The method of claim 1488, wherein the one or more heat sources comprise flameless distributed combustors.

1495. The method of claim 1488, wherein the one or more heat sources comprise natural distributed combustors.

1496. The method of claim 1488, further comprising controlling a pressure and a temperature within at least a majority of the selected section of the formation, wherein the pressure is controlled as a function of temperature, or the temperature is controlled as a function of pressure.

1497. The method of claim 1488, further comprising controlling the heat such that an average heating rate of the selected section is less than about 1° C. per day during pyrolysis.

1498. The method of claim 1488, wherein providing heat from the one or more heat sources to at least the portion of formation comprises:

heating a selected volume (V) of the oil shale formation from the one or more heat sources, wherein the formation has an average heat capacity (Cv), and wherein the heating pyrolyzes at least some hydrocarbons within the selected volume of the formation; and

wherein heating energy/day provided to the volume is equal to or less than Pwr, wherein Pwr is calculated by the equation:

Pwr h*V*Cv*ρB

wherein Pwr is the heating energy/day, h is an average heating rate of the formation, ρB is formation bulk density, and wherein the heating rate is less than about 10° C./day.

1500. The method of claim 1488, wherein providing heat from the one or more heat sources comprises heating the selected section such that a thermal conductivity of at least a portion of the selected section is greater than about 0.5 W/(m ° C.).

1501. The method of claim 1488, wherein the produced mixture comprises condensable hydrocarbons having an API gravity of at least about 25°.

1502. The method of claim 1488, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 0.1% by weight to about 15% by weight of the condensable hydrocarbons are olefins.

1503. The method of claim 1488, wherein the produced mixture comprises non-condensable hydrocarbons, and wherein a molar ratio of ethene to ethane in the non-condensable hydrocarbons ranges from about 0.001 to about 0.15.

1504. The method of claim 1488, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is nitrogen.

1505. The method of claim 1488, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is oxygen.

1506. The method of claim 1488, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is sulfur.

1507. The method of claim 1488, wherein the produced mixture comprises condensable hydrocarbons, wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons comprise oxygen containing compounds, and wherein the oxygen containing compounds comprise phenols.

1508. The method of claim 1488, wherein the produced mixture comprises condensable hydrocarbons, and wherein greater than about 20% by weight of the condensable hydrocarbons are aromatic compounds.

1509. The method of claim 1488, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 5% by weight of the condensable hydrocarbons comprises multi-ring aromatics with more than two rings.

1510. The method of claim 1488, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 0.3% by weight of the condensable hydrocarbons are asphaltenes.

1511. The method of claim 1488, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons are cycloalkanes.

1512. The method of claim 1488, wherein the produced mixture comprises anon-condensable component, wherein the non-condensable component comprises hydrogen, wherein the hydrogen is greater than about 10% by volume of the non-condensable component, and wherein the hydrogen is less than about 80% by volume of the non-condensable component.

1513. The method of claim 1488, wherein the produced mixture comprises ammonia, and wherein greater than about 0.05% by weight of the produced mixture is ammonia.

1514. The method of claim 1488, wherein the produced mixture comprises ammonia, and wherein the ammonia is used to produce fertilizer.

1515. The method of claim 1488, further comprising controlling a pressure within at least a majority of the selected section of the formation, wherein the controlled pressure is at least about 2.0 bars absolute.

1516. The method of claim 1488, further comprising controlling formation conditions to produce the mixture, wherein a partial pressure of H2 within the mixture is greater than about 0.5 bars.

1517. The method of claim 1488, wherein a partial pressure of H2 within the mixture is measured when the mixture is at a production well.

1518. The method of claim 1488, further comprising altering a pressure within the formation to inhibit production of hydrocarbons from the formation having carbon numbers greater than about 25.

1519. The method of claim 1488, wherein providing hydrogen (H2) to the formation further comprises:

hydrogenating hydrocarbons within the section; and

heating a portion of the section with heat from hydrogenation.

1520. The method of claim 1488, further comprising:

producing hydrogen and condensable hydrocarbons from the formation; and

hydrogenating a portion of the produced condensable hydrocarbons with at least a portion of the produced hydrogen.

1521. The method of claim 1488, wherein allowing the heat to transfer comprises increasing a permeability of a majority of the selected section to greater than about 100 millidarcy.

1522. The method of claim 1488, wherein allowing the heat to transfer comprises substantially uniformly increasing a permeability of a majority of the selected section.

1523. The method of claim 1488, further comprising controlling the heat to yield greater than about 60% by weight of condensable hydrocarbons, as measured by Fischer Assay.

1524. The method of claim 1488, wherein producing the mixture comprises producing the mixture in a production well, and wherein at least about 7 heat sources are disposed in the formation for each production well.

1525. The method of claim 1524, wherein at least about 20 heat sources are disposed in the formation for each production well.

1526. The method of claim 1488, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, and wherein the unit of heat sources comprises a triangular pattern.

1527. The method of claim 1488, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, wherein the unit of heat sources comprises a triangular pattern, and wherein a plurality of the units are repeated over an area of the formation to form a repetitive pattern of units.

1528. A method of treating an oil shale formation in situ, comprising:

providing heat from one or more heat sources to at least a portion of the formation;

allowing the heat to transfer from the one or more heat sources to a selected section of the formation;

providing H2 to the selected section to hydrogenate hydrocarbons within the selected section and to heat a portion of the section with heat from the hydrogenation; and

controlling heating of the selected section by controlling amounts of H2 provided to the selected section.

1529. The method of claim 1528, wherein the one or more heat sources comprise at least two heat sources, and wherein superposition of heat from at least the two heat sources pyrolyzes at least some hydrocarbons within the selected section of the formation.

1530. The method of claim 1528, further comprising maintaining a temperature within the selected section within a pyrolysis temperature range.

1531. The method of claim 1528, wherein the one or more heat sources comprise electrical heaters.

1532. The method of claim 1528, wherein the one or more heat sources comprise surface burners.

1533. The method of claim 1528, wherein the one or more heat sources comprise flameless distributed combustors.

1534. The method of claim 1528, wherein the one or more heat sources comprise natural distributed combustors.

1535. The method of claim 1528, further comprising controlling a pressure and a temperature within at least a majority of the selected section of the formation, wherein the pressure is controlled as a function of temperature, or the temperature is controlled as a function of pressure.

1536. The method of claim 1528, further comprising controlling the heat such that an average heating rate of the selected section is less than about 1° C. per day during pyrolysis.

1537. The method of claim 1528, wherein providing heat from the one or more heat sources to at least the portion of formation comprises:

heating a selected volume (V) of the oil shale formation from the one or more heat sources, wherein the formation has an average heat capacity (Cv), and wherein the heating pyrolyzes at least some hydrocarbons within the selected volume of the formation; and

wherein heating energy/day provided to the volume is equal to or less than Pwr, wherein Pwr is calculated by the equation:

Pwr=h*V*Cv*ρB

wherein Pwr is the heating energy/day, h is an average heating rate of the formation, ρB is formation bulk density, and wherein the heating rate is less than about 10° C./day.

1539. The method of claim 1528, wherein providing heat from the one or more heat sources comprises heating the selected section such that a thermal conductivity of at least a portion of the selected section is greater than about 0.5 W/(m ° C.).

1540. The method of claim 1528, further comprising producing a mixture from the formation, wherein the produced mixture comprises condensable hydrocarbons having an API gravity of at least about 25°.

1541. The method of claim 1528, further comprising producing a mixture from the formation, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 0.1% by weight to about 15% by weight of the condensable hydrocarbons are olefins.

1542. The method of claim 1528, further comprising producing a mixture from the formation, wherein the produced mixture comprises non-condensable hydrocarbons, and wherein a molar ratio of ethene to ethane in the non-condensable hydrocarbons ranges from about 0.001 to about 0.15.

1543. The method of claim 1528, further comprising producing a mixture from the formation, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is nitrogen.

1544. The method of claim 1528, further comprising producing a mixture from the formation, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is oxygen.

1545. The method of claim 1528, further comprising producing a mixture from the formation, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is sulfur.

1546. The method of claim 1528, further comprising producing a mixture from the formation, wherein the produced mixture comprises condensable hydrocarbons, wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons comprise oxygen containing compounds, and wherein the oxygen containing compounds comprise phenols.

1547. The method of claim 1528, further comprising producing a mixture from the formation, wherein the produced mixture comprises condensable hydrocarbons, and wherein greater than about 20% by weight of the condensable hydrocarbons are aromatic compounds.

1548. The method of claim 1528, further comprising producing a mixture from the formation, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 5% by weight of the condensable hydrocarbons comprises multi-ring aromatics with more than two rings.

1549. The method of claim 1528, further comprising producing a mixture from the formation, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 0.3% by weight of the condensable hydrocarbons are asphaltenes.

1550. The method of claim 1528, further comprising producing a mixture from the formation, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons are cycloalkanes.

1551. The method of claim 1528, further comprising producing a mixture from the formation, wherein the produced mixture comprises a non-condensable component, wherein the non-condensable component comprises hydrogen, wherein the hydrogen is greater than about 10% by volume of the non-condensable component, and wherein the hydrogen is less than about 80% by volume of the non-condensable component.

1552. The method of claim 1528, further comprising producing a mixture from the formation, wherein the produced mixture comprises ammonia, and wherein greater than about 0.05% by weight of the produced mixture is ammonia

1553. The method of claim 1528, further comprising producing a mixture from the formation, wherein the produced mixture comprises ammonia, and wherein the ammonia is used to produce fertilizer.

1554. The method of claim 1528, further comprising controlling a pressure within at least a majority of the selected section of the formation, wherein the controlled pressure is at least about 2.0 bars absolute.

1555. The method of claim 1528, further comprising controlling formation conditions to produce a mixture from the formation, wherein a partial pressure of H2 within the mixture is greater than about 0.5 bars.

1556. The method of claim 1555, wherein the partial pressure of H2 within the mixture is measured when the mixture is at a production well.

1557. The method of claim 1528, further comprising altering a pressure within the formation to inhibit production of hydrocarbons from the formation having carbon numbers greater than about 25.

1558. The method of claim 1528, further comprising controlling formation conditions by recirculating a portion of hydrogen from a produced mixture into the formation.

1559. The method of claim 1528, further comprising:

producing hydrogen and condensable hydrocarbons from the formation; and

hydrogenating a portion of the produced condensable hydrocarbons with at least a portion of the produced hydrogen.

1560. The method of claim 1528, wherein allowing the heat to transfer comprises increasing a permeability of a majority of the selected section to greater than about 100 millidarcy.

1561. The method of claim 1528, wherein allowing the heat to transfer comprises substantially uniformly increasing a permeability of a majority of the selected section.

1562. The method of claim 1528, further comprising producing a mixture in a production well, and wherein at least about 7 heat sources are disposed in the formation for each production well.

1563. The method of claim 1562, wherein at least about 20 heat sources are disposed in the formation for each production well.

1564. The method of claim 1528, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, and wherein the unit of heat sources comprises a triangular pattern.

1565. The method of claim 1528, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, wherein the unit of heat sources comprises a triangular pattern, and wherein a plurality of the units are repeated over an area of the formation to form a repetitive pattern of units.

1566. An in situ method for producing H2 from an oil shale formation, comprising:

providing heat from one or more heat sources to at least a portion of the formation;

allowing the heat to transfer from the one or more heat sources to a selected section of the formation; and

producing a mixture from the formation, wherein a H2 partial pressure within the mixture is greater than about 0.5 bars.

1567. The method of claim 1566, wherein the one or more heat sources comprise at least two heat sources, and wherein superposition of heat from at least the two heat sources pyrolyzes at least some hydrocarbons within the selected section of the formation.

1568. The method of claim 1566, further comprising maintaining a temperature within the selected section within a pyrolysis temperature range.

1569. The method of claim 1566, wherein the one or more heat sources comprise electrical heaters.

1570. The method of claim 1566, wherein the one or more heat sources comprise surface burners.

1571. The method of claim 1566, wherein the one or more heat sources comprise flameless distributed combustors.

1572. The method of claim 1566, wherein the one or more heat sources comprise natural distributed combustors.

1573. The method of claim 1566, further comprising controlling a pressure and a temperature within at least a majority of the selected section of the formation, wherein the pressure is controlled as a function of temperature, or the temperature is controlled as a function of pressure.

1574. The method of claim 1566, further comprising controlling the heat such that an average heating rate of the selected section is less than about 1° C. per day during pyrolysis.

1575. The method of claim 1566, wherein providing heat from the one or more heat sources to at least the portion of formation comprises:

heating a selected volume (V) of the oil shale formation from the one or more heat sources, wherein the formation has an average heat capacity (Cv), and wherein the heating pyrolyzes at least some hydrocarbons within the selected volume of the formation; and

wherein heating energy/day provided to the volume is equal to or less than Pwr, wherein Pwr is calculated by the equation:

Pwr=h*V*Cv*ρB

wherein Pwr is the heating energy/day, h is an average heating rate of the formation, ρB is formation bulk density, and wherein the heating rate is less than about 10° C./day.

1577. The method of claim 1566, wherein providing heat from the one or more heat sources comprises heating the selected section such that a thermal conductivity of at least a portion of the selected section is greater than about 0.5 W/(m ° C.).

1578. The method of claim 1566, wherein the produced mixture comprises condensable hydrocarbons having an API gravity of at least about 25°.

1579. The method of claim 1566, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 0.1% by weight to about 15% by weight of the condensable hydrocarbons are olefins.

1580. The method of claim 1566, wherein the produced mixture comprises non-condensable hydrocarbons, and wherein a molar ratio of ethene to ethane in the non-condensable hydrocarbons ranges from about 0.001 to about 0.15.

1581. The method of claim 1566, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is nitrogen.

1582. The method of claim 1566, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is oxygen.

1583. The method of claim 1566, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is sulfur.

1584. The method of claim 1566, wherein the produced mixture comprises condensable hydrocarbons, wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons comprise oxygen containing compounds, and wherein the oxygen containing compounds comprise phenols.

1585. The method of claim 1566, wherein the produced mixture comprises condensable hydrocarbons, and wherein greater than about 20% by weight of the condensable hydrocarbons are aromatic compounds.

1586. The method of claim 1566, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 5% by weight of the condensable hydrocarbons comprises multi-ring aromatics with more than two rings.

1587. The method of claim 1566, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 0.3% by weight of the condensable hydrocarbons are asphaltenes.

1588. The method of claim 1566, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons are cycloalkanes.

1589. The method of claim 1566, wherein the produced mixture comprises a non-condensable component, wherein the non-condensable component comprises hydrogen, wherein the hydrogen is greater than about 10% by volume of the non-condensable component, and wherein the hydrogen is less than about 80% by volume of the non-condensable component.

1590. The method of claim 1566, wherein the produced mixture comprises ammonia, and wherein greater than about 0.05% by weight of the produced mixture is ammonia.

1591. The method of claim 1566, wherein the produced mixture comprises ammonia, and wherein the ammonia is used to produce fertilizer.

1592. The method of claim 1566, further comprising controlling a pressure within at least a majority of the selected section of the formation, wherein the controlled pressure is at least about 2.0 bars absolute.

1593. The method of claim 1566, further comprising altering a pressure within the formation to inhibit production of hydrocarbons from the formation having carbon numbers greater than about 25.

1594. The method of claim 1566, further comprising recirculating a portion of the hydrogen within the mixture into the formation.

1595. The method of claim 1566, further comprising condensing a hydrocarbon component from the produced mixture and hydrogenating the condensed hydrocarbons with a portion of the hydrogen.

1596. The method of claim 1566, further comprising:

providing hydrogen (H2) to the heated section to hydrogenate hydrocarbons within the section; and

heating a portion of the section with heat from hydrogenation.

1597. The method of claim 1566, wherein allowing the heat to transfer comprises increasing a permeability of a majority of the selected section to greater than about 100 millidarcy.

1598. The method of claim 1566, wherein allowing the heat to transfer comprises substantially uniformly increasing a permeability of a majority of the selected section.

1599. The method of claim 1566, further comprising controlling the heat to yield greater than about 60% by weight of condensable hydrocarbons, as measured by Fischer Assay.

1600. The method of claim 1566, wherein producing the mixture comprises producing the mixture in a production well, and wherein at least about 7 heat sources are disposed in the formation for each production well.

1601. The method of claim 1600, wherein at least about 20 heat sources are disposed in the formation for each production well.

1602. The method of claim 1566, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, and wherein the unit of heat sources comprises a triangular pattern.

1603. The method of claim 1566, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, wherein the unit of heat sources comprises a triangular pattern, and wherein a plurality of the units are repeated over an area of the formation to form a repetitive pattern of units.

1604. The method of claim 1566, wherein a partial pressure of H2 within the mixture is measured when the mixture is at a production well.

1605. A method of treating an oil shale formation in situ, comprising:

providing heat from one or more heat sources to at least a portion of the formation;

allowing the heat to transfer from the one or more heat sources to a selected section of the formation;

wherein the selected section has been selected for heating using an atomic hydrogen weight percentage of at least a portion of hydrocarbons in the selected section, and wherein at least the portion of the hydrocarbons in the selected section comprises an atomic hydrogen weight percentage, when measured on a dry, ash-free basis, of greater than about 4.0%; and

producing a mixture from the formation.

1606. The method of claim 1605, wherein the one or more heat sources comprise at least two heat sources, and wherein superposition of heat from at least the two heat sources pyrolyzes at least some hydrocarbons within the selected section of the formation.

1607. The method of claim 1605, further comprising maintaining a temperature within the selected section within a pyrolysis temperature range.

1608. The method of claim 1605, wherein the one or more heat sources comprise electrical heaters.

1609. The method of claim 1605, wherein the one or more heat sources comprise surface burners.

1610. The method of claim 1605, wherein the one or more heat sources comprise flameless distributed combustors.

1611. The method of claim 1605, wherein the one or more heat sources comprise natural distributed combustors.

1612. The method of claim 1605, further comprising controlling a pressure and a temperature within at least a majority of the selected section of the formation, wherein the pressure is controlled as a function of temperature, or the temperature is controlled as a function of pressure.

1613. The method of claim 1605, further comprising controlling the heat such that an average heating rate of the selected section is less than about 1° C. per day during pyrolysis.

1614. The method of claim 1605, wherein providing heat from the one or more heat sources to at least the portion of formation comprises:

heating a selected volume (V) of the oil shale formation from the one or more heat sources, wherein the formation has an average heat capacity (Cv), and wherein the heating pyrolyzes at least some hydrocarbons within the selected volume of the formation; and

wherein heating energy/day provided to the volume is equal to or less than Pwr, wherein Pwr is calculated by the equation:

Pwr=h*V*Cv*ρB

wherein Pwr is the heating energy/day, h is an average heating rate of the formation, ρB is formation bulk density, and wherein the heating rate is less than about 10° C./day.

1616. The method of claim 1605, wherein providing heat from the one or more heat sources comprises heating the selected section such that a thermal conductivity of at least a portion of the selected section is greater than about 0.5 W/(m ° C.).

1617. The method of claim 1605, wherein the produced mixture comprises condensable hydrocarbons having an API gravity of at least about 25°.

1618. The method of claim 1605, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 0.1% by weight to about 15% by weight of the condensable hydrocarbons are olefins.

1619. The method of claim 1605, wherein the produced mixture comprises non-condensable hydrocarbons, and wherein a molar ratio of ethene to ethane in the non-condensable hydrocarbons ranges from about 0.001 to about 0.15.

1620. The method of claim 1605, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is nitrogen.

1621. The method of claim 1605, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is oxygen.

1622. The method of claim 1605, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is sulfur.

1623. The method of claim 1605, wherein the produced mixture comprises condensable hydrocarbons, wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons comprise oxygen containing compounds, and wherein the oxygen containing compounds comprise phenols.

1624. The method of claim 1605, wherein the produced mixture comprises condensable hydrocarbons, and wherein greater than about 20% by weight of the condensable hydrocarbons are aromatic compounds.

1625. The method of claim 1605, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 5% by weight of the condensable hydrocarbons comprises multi-ring aromatics with more than two rings.

1626. The method of claim 1605, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 0.3% by weight of the condensable hydrocarbons are asphaltenes.

1627. The method of claim 1605, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons are cycloalkanes.

1628. The method of claim 1605, wherein the produced mixture comprises a non-condensable component, wherein the non-condensable component comprises hydrogen, wherein the hydrogen is greater than about 10% by volume of the non-condensable component, and wherein the hydrogen is less than about 80% by volume of the non-condensable component.

1629. The method of claim 1605, wherein the produced mixture comprises ammonia, and wherein greater than about 0.05% by weight of the produced mixture is ammonia.

1630. The method of claim 1605, wherein the produced mixture comprises ammonia, and wherein the ammonia is used to produce fertilizer.

1631. The method of claim 1605, further comprising controlling a pressure within at least a majority of the selected section of the formation, wherein the controlled pressure is at least about 2.0 bars absolute.

1632. The method of claim 1605, further comprising controlling formation conditions to produce the mixture, wherein a partial pressure of H2 within the mixture is greater than about 0.5 bars.

1633. The method of claim 1632, wherein the partial pressure of H2 within the mixture is measured when the mixture is at a production well.

1634. The method of claim 1605, further comprising altering a pressure within the formation to inhibit production of hydrocarbons from the formation having carbon numbers greater than about 25.

1635. The method of claim 1605, further comprising controlling formation conditions by recirculating a portion of hydrogen from the mixture into the formation.

1636. The method of claim 1605, further comprising:

providing hydrogen (H2) to the heated section to hydrogenate hydrocarbons within the section; and

heating a portion of the section with heat from hydrogenation.

1637. The method of claim 1605, further comprising:

producing hydrogen and condensable hydrocarbons from the formation; and

hydrogenating a portion of the produced condensable hydrocarbons with at least a portion of the produced hydrogen.

1638. The method of claim 1605, wherein allowing the heat to transfer comprises increasing a permeability of a majority of the selected section to greater than about 100 millidarcy.

1639. The method of claim 1605, wherein allowing the heat to transfer comprises substantially uniformly increasing a permeability of a majority of the selected section.

1640. The method of claim 1605, further comprising controlling the heat to yield greater than about 60% by weight of condensable hydrocarbons, as measured by Fischer Assay.

1641. The method of claim 1605, wherein producing the mixture comprises producing the mixture in a production well, and wherein at least about 7 heat sources are disposed in the formation for each production well.

1642. The method of claim 1641, wherein at least about 20 heat sources are disposed in the formation for each production well.

1643. The method of claim 1605, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, and wherein the unit of heat sources comprises a triangular pattern.

1644. The method of claim 1605, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, wherein the unit of heat sources comprises a triangular pattern, and wherein a plurality of the units are repeated over an area of the formation to form a repetitive pattern of units.

1645. A method of treating an oil shale formation in situ, comprising:

providing heat from one or more heat sources to at least a portion of the formation;

allowing the heat to transfer from the one or more heat sources to a selected section of the formation;

wherein at least some hydrocarbons within the selected section have an initial atomic hydrogen weight percentage of greater than about 4.0%; and

producing a mixture from the formation.

1646. The method of claim 1645, wherein the one or more heat sources comprise at least two heat sources, and wherein superposition of heat from at least the two heat sources pyrolyzes at least some hydrocarbons within the selected section of the formation.

1647. The method of claim 1645, further comprising maintaining a temperature within the selected section within a pyrolysis temperature range.

1648. The method of claim 1645, wherein the one or more heat sources comprise electrical heaters.

1649. The method of claim 1645, wherein the one or more heat sources comprise surface burners.

1650. The method of claim 1645, wherein the one or more heat sources comprise flameless distributed combustors.

1651. The method of claim 1645, wherein the one or more heat sources comprise natural distributed combustors.

1652. The method of claim 1645, further comprising controlling a pressure and a temperature within at least a majority of the selected section of the formation, wherein the pressure is controlled as a function of temperature, or the temperature is controlled as a function of pressure.

1653. The method of claim 1645, further comprising controlling the heat such that an average heating rate of the selected section is less than about 1° C. per day during pyrolysis.

1654. The method of claim 1645, wherein providing heat from the one or more heat sources to at least the portion of formation comprises:

heating a selected volume (V) of the oil shale formation from the one or more heat sources, wherein the formation has an average heat capacity (Cv), and wherein the heating pyrolyzes at least some hydrocarbons within the selected volume of the formation; and

wherein heating energy/day provided to the volume is equal to or less than Pwr, wherein Pwr is calculated by the equation:

Pwr h*V*Cv*ρB

wherein Pwr is the heating energy/day, h is an average heating rate of the formation, ρB is formation bulk density, and wherein the heating rate is less than about 10° C./day.

1656. The method of claim 1645, wherein providing heat from the one or more heat sources comprises heating the selected section such that a thermal conductivity of at least a portion of the selected section is greater than about 0.5 W/(m ° C.).

1657. The method of claim 1645, wherein the produced mixture comprises condensable hydrocarbons having an API gravity of at least about 25°.

1658. The method of claim 1645, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 0.1% by weight to about 15% by weight of the condensable hydrocarbons are olefins.

1659. The method of claim 1645, wherein the produced mixture comprises non-condensable hydrocarbons, and wherein a molar ratio of ethene to ethane in the non-condensable hydrocarbons ranges from about 0.001 to about 0.15.

1660. The method of claim 1645, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is nitrogen.

1661. The method of claim 1645, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is oxygen.

1662. The method of claim 1645, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is sulfur.

1663. The method of claim 1645, wherein the produced mixture comprises condensable hydrocarbons, wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons comprise oxygen containing compounds, and wherein the oxygen containing compounds comprise phenols.

1664. The method of claim 1645, wherein the produced mixture comprises condensable hydrocarbons, and wherein greater than about 20% by weight of the condensable hydrocarbons are aromatic compounds.

1665. The method of claim 1645, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 5% by weight of the condensable hydrocarbons comprises multi-ring aromatics with more than two rings.

1666. The method of claim 1645, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 0.3% by weight of the condensable hydrocarbons are asphaltenes.

1667. The method of claim 1645, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons are cycloalkanes.

1668. The method of claim 1645, wherein the produced mixture comprises a non-condensable component, wherein the non-condensable component comprises hydrogen, wherein the hydrogen is greater than about 10% by volume of the non-condensable component, and wherein the hydrogen is less than about 80% by volume of the non-condensable component.

1669. The method of claim 1645, wherein the produced mixture comprises ammonia, and wherein greater than about 0.05% by weight of the produced mixture is ammonia.

1670. The method of claim 1645, wherein the produced mixture comprises ammonia, and wherein the ammonia is used to produce fertilizer.

1671. The method of claim 1645, further comprising controlling a pressure within at least a majority of the selected section of the formation, wherein the controlled pressure is at least about 2.0 bars absolute.

1672. The method of claim 1645, further comprising controlling formation conditions to produce the mixture, wherein a partial pressure of H2 within the mixture is greater than about 0.5 bars.

1673. The method of claim 1672, wherein the partial pressure of H2 within the mixture is measured when the mixture is at a production well.

1674. The method of claim 1645, further comprising altering a pressure within the formation to inhibit production of hydrocarbons from the formation having carbon numbers greater than about 25.

1675. The method of claim 1645, further comprising controlling formation conditions by recirculating a portion of hydrogen from the mixture into the formation.

1676. The method of claim 1645, further comprising:

providing hydrogen (H2) to the heated section to hydrogenate hydrocarbons within the section; and

heating a portion of the section with heat from hydrogenation.

1677. The method of claim 1645, further comprising:

producing hydrogen and condensable hydrocarbons from the formation; and

hydrogenating a portion of the produced condensable hydrocarbons with at least a portion of the produced hydrogen.

1678. The method of claim 1645, wherein allowing the heat to transfer comprises increasing a permeability of a majority of the selected section to greater than about 100 millidarcy.

1679. The method of claim 1645, wherein allowing the heat to transfer comprises substantially uniformly increasing a permeability of a majority of the selected section.

1680. The method of claim 1645, further comprising controlling the heat to yield greater than about 60% by weight of condensable hydrocarbons, as measured by Fischer Assay.

1681. The method of claim 1645, wherein producing the mixture comprises producing the mixture in a production well, and wherein at least about 7 heat sources are disposed in the formation for each production well.

1682. The method of claim 1681, wherein at least about 20 heat sources are disposed in the formation for each production well.

1683. The method of claim 1645, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, and wherein the unit of heat sources comprises a triangular pattern.

1684. The method of claim 1645, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, wherein the unit of heat sources comprises a triangular pattern, and wherein a plurality of the units are repeated over an area of the formation to form a repetitive pattern of units.

1685. A method of treating an oil shale formation in situ, comprising:

providing heat from one or more heat sources to at least a portion of the formation;

allowing the heat to transfer from the one or more heat sources to a selected section of the formation;

wherein the selected section has been selected for heating using vitrinite reflectance of at least some hydrocarbons in the selected section, and wherein at least a portion of the hydrocarbons in the selected section comprises a vitrinite reflectance of greater than about 0.3%;

wherein at least a portion of the hydrocarbons in the selected section comprises a vitrinite reflectance of less than about 4.5%; and

producing a mixture from the formation.

1686. The method of claim 1685, wherein the one or more heat sources comprise at least two heat sources, and wherein superposition of heat from at least the two heat sources pyrolyzes at least some hydrocarbons within the selected section of the formation.

1687. The method of claim 1685, further comprising maintaining a temperature within the selected section within a pyrolysis temperature.

1688. The method of claim 1685, wherein the vitrinite reflectance of at least the portion of hydrocarbons within the selected section is between about 0.47% and about 1.5% such that a majority of the produced mixture comprises condensable hydrocarbons.

1689. The method of claim 1685, wherein the vitrinite reflectance of at least the portion of hydrocarbons within the selected section is between about 1.4% and about 4.2% such that a majority of the produced mixture comprises non-condensable hydrocarbons.

1690. The method of claim 1685, wherein the one or more heat sources comprise electrical heaters.

1691. The method of claim 1685, wherein the one or more heat sources comprise surface burners.

1692. The method of claim 1685, wherein the one or more heat sources comprise flameless distributed combustors

1693. The method of claim 1685, wherein the one or more heat sources comprise natural distributed combustors.

1694. The method of claim 1685, further comprising controlling a pressure and a temperature within at least a majority of the selected section of the formation, wherein the pressure is controlled as a function of temperature, or the temperature is controlled as a function of pressure.

1695. The method of claim 1685, further comprising controlling the heat such that an average heating rate of the selected section is less than about 1° C. per day during pyrolysis.

1696. The method of claim 1685, wherein providing heat from the one or more heat sources to at least the portion of formation comprises:

heating a selected volume (V) of the oil shale formation from the one or more heat sources, wherein the formation has an average heat capacity (Cv), and wherein the heating pyrolyzes at least some hydrocarbons within the selected volume of the formation; and

wherein heating energy/day provided to the volume is equal to or less than Pwr, wherein Pwr is calculated by the equation:

Pwr=h*V*Cv*ρB

wherein Pwr is the heating energy/day, h is an average heating rate of the formation, ρB is formation bulk density, and wherein the heating rate is less than about 10° C./day.

1698. The method of claim 1685, wherein providing heat from the one or more heat sources comprises heating the selected section such that a thermal conductivity of at least a portion of the selected section is greater than about 0.5 W/(m ° C.).

1699. The method of claim 1685, wherein the produced mixture comprises condensable hydrocarbons having an API gravity of at least about 25°.

1700. The method of claim 1685, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 0.1% by weight to about 15% by weight of the condensable hydrocarbons are olefins.

1701. The method of claim 1685, wherein the produced mixture comprises non-condensable hydrocarbons, and wherein a molar ratio of ethene to ethane in the non-condensable hydrocarbons ranges from about 0.001 to about 0.15.

1702. The method of claim 1685, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is nitrogen.

1703. The method of claim 1685, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is oxygen.

1704. The method of claim 1685, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is sulfur.

1705. The method of claim 1685, wherein the produced mixture comprises condensable hydrocarbons, wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons comprise oxygen containing compounds, and wherein the oxygen containing compounds comprise phenols.

1706. The method of claim 1685, wherein the produced mixture comprises condensable hydrocarbons, and wherein greater than about 20% by weight of the condensable hydrocarbons are aromatic compounds.

1707. The method of claim 1685, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 5% by weight of the condensable hydrocarbons comprises multi-ring aromatics with more than two rings.

1708. The method of claim 1685, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 0.3% by weight of the condensable hydrocarbons are asphaltenes.

1709. The method of claim 1685, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons are cycloalkanes.

1710. The method of claim 1685, wherein the produced mixture comprises a non-condensable component, wherein the non-condensable component comprises hydrogen, wherein the hydrogen is greater than about 10% by volume of the non-condensable component, and wherein the hydrogen is less than about 80% by volume of the non-condensable component.

1711. The method of claim 1685, wherein the produced mixture comprises ammonia, and wherein greater than about 0.05% by weight of the produced mixture is ammonia.

1712. The method of claim 1685, wherein the produced mixture comprises ammonia, and wherein the ammonia is used to produce fertilizer.

1713. The method of claim 1685, further comprising controlling a pressure within at least a majority of the selected section of the formation, wherein the controlled pressure is at least about 2.0 bars absolute.

1714. The method of claim 1685, further comprising controlling formation conditions to produce the mixture, wherein a partial pressure of H2 within the mixture is greater than about 0.5 bars.

1715. The method of claim 1714, wherein the partial pressure of H2 within the mixture is measured when the mixture is at a production well.

1716. The method of claim 1685, further comprising altering a pressure within the formation to inhibit production of hydrocarbons from the formation having carbon numbers greater than about 25.

1717. The method of claim 1685, further comprising controlling formation conditions by recirculating a portion of hydrogen from the mixture into the formation.

1718. The method of claim 1685, further comprising:

providing hydrogen (H2) to the heated section to hydrogenate hydrocarbons within the section; and

heating a portion of the section with heat from hydrogenation.

1719. The method of claim 1685, further comprising:

producing hydrogen and condensable hydrocarbons from the formation; and

hydrogenating a portion of the produced condensable hydrocarbons with at least a portion of the produced hydrogen.

1720. The method of claim 1685, wherein allowing the heat to transfer comprises increasing a permeability of a majority of the selected section to greater than about 100 millidarcy.

1721. The method of claim 1685, wherein allowing the heat to transfer comprises substantially uniformly increasing a permeability of a majority of the selected section.

1722. The method of claim 1685, further comprising controlling the heat to yield greater than about 60% by weight of condensable hydrocarbons, as measured by Fischer Assay.

1723. The method of claim 1685, wherein producing the mixture comprises producing the mixture in a production well, and wherein at least about 7 heat sources are disposed in the formation for each production well.

1724. The method of claim 1723, wherein at least about 20 heat sources are disposed in the formation for each production well.

1725. The method of claim 1685, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, and wherein the unit of heat sources comprises a triangular pattern.

1726. The method of claim 1685, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, wherein the unit of heat sources comprises a triangular pattern, and wherein a plurality of the units are repeated over an area of the formation to form a repetitive pattern of units.

1727. A method of treating an oil shale formation in situ, comprising:

providing heat from one or more heat sources to at least a portion of the formation;

allowing the heat to transfer from the one or more heat sources to a selected section of the formation;

wherein the selected section has been selected for heating using a total organic matter weight percentage of at least a portion of the selected section, and wherein at least the portion of the selected section comprises a total organic matter weight percentage, of at least about 5.0%; and

producing a mixture from the formation.

1728. The method of claim 1727, wherein the one or more heat sources comprise at least two heat sources, and wherein superposition of heat from at least the two heat sources pyrolyzes at least some hydrocarbons within the selected section of the formation.

1729. The method of claim 1727, further comprising maintaining a temperature within the selected section within a pyrolysis temperature range.

1730. The method of claim 1727, wherein the one or more heat sources comprise electrical heaters.

1731. The method of claim 1727, wherein the one or more heat sources comprise surface burners.

1732. The method of claim 1727, wherein the one or more heat sources comprise flameless distributed combustors.

1733. The method of claim 1727, wherein the one or more heat sources comprise natural distributed combustors.

1734. The method of claim 1727, further comprising controlling a pressure and a temperature within at least a majority of the selected section of the formation, wherein the pressure is controlled as a function of temperature, or the temperature is controlled as a function of pressure.

1735. The method of claim 1727, further comprising controlling the heat such that an average heating rate of the selected section is less than about 1° C. per day during pyrolysis.

1736. The method of claim 1727, wherein providing heat from the one or more heat sources to at least the portion of formation comprises:

heating a selected volume (V) of the oil shale formation from the one or more heat sources, wherein the formation has an average heat capacity (Cv), and wherein the heating pyrolyzes at least some hydrocarbons within the selected volume of the formation; and

wherein heating energy/day provided to the volume is equal to or less than Pwr, wherein Pwr is calculated by the equation:

Pwr=h*V*Cv*ρB

wherein Pwr is the heating energy/day, h is an average heating rate of the formation, ρB is formation bulk density, and wherein the heating rate is less than about 10° C./day.

1738. The method of claim 1727, wherein providing heat from the one or more heat sources comprises heating the selected section such that a thermal conductivity of at least a portion of the selected section is greater than about 0.5 W/(m ° C.).

1739. The method of claim 1727, wherein the produced mixture comprises condensable hydrocarbons having an API gravity of at least about 25°.

1740. The method of claim 1727, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 0.1% by weight to about 15% by weight of the condensable hydrocarbons are olefins.

1741. The method of claim 1727, wherein the produced mixture comprises non-condensable hydrocarbons, and wherein a molar ratio of ethene to ethane in the non-condensable hydrocarbons ranges from about 0.001 to about 0.15.

1742. The method of claim 1727, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is nitrogen.

1743. The method of claim 1727, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is oxygen.

1744. The method of claim 1727, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is sulfur.

1745. The method of claim 1727, wherein the produced mixture comprises condensable hydrocarbons, wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons comprise oxygen containing compounds, and wherein the oxygen containing compounds comprise phenols.

1746. The method of claim 1727, wherein the produced mixture comprises condensable hydrocarbons, and wherein greater than about 20% by weight of the condensable hydrocarbons are aromatic compounds.

1747. The method of claim 1727, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 5% by weight of the condensable hydrocarbons comprises multi-ring aromatics with more than two rings.

1748. The method of claim 1727, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 0.3% by weight of the condensable hydrocarbons are asphaltenes.

1749. The method of claim 1727, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons are cycloalkanes.

1750. The method of claim 1727, wherein the produced mixture comprises a non-condensable component, wherein the non-condensable component comprises hydrogen, wherein the hydrogen is greater than about 10% by volume of the non-condensable component, and wherein the hydrogen is less than about 80% by volume of the non-condensable component.

1751. The method of claim 1727, wherein the produced mixture comprises ammonia, and wherein greater than about 0.05% by weight of the produced mixture is ammonia.

1752. The method of claim 1727, wherein the produced mixture comprises ammonia, and wherein the ammonia is used to produce fertilizer.

1753. The method of claim 1727, further comprising controlling a pressure within at least a majority of the selected section of the formation, wherein the controlled pressure is at least about 2.0 bars absolute.

1754. The method of claim 1727, further comprising controlling formation conditions to produce the mixture, wherein a partial pressure of H2 within the mixture is greater than about 0.5 bars.

1755. The method of claim 1754, wherein the partial pressure of H2 within the mixture is measured when the mixture is at a production well.

1756. The method of claim 1727, further comprising altering a pressure within the formation to inhibit production of hydrocarbons from the formation having carbon numbers greater than about 25.

1757. The method of claim 1727, further comprising controlling formation conditions by recirculating a portion of hydrogen from the mixture into the formation.

1758. The method of claim 1727, further comprising:

providing hydrogen (H2) to the heated section to hydrogenate hydrocarbons within the section; and

heating a portion of the section with heat from hydrogenation.

1759. The method of claim 1727, further comprising:

producing hydrogen and condensable hydrocarbons from the formation; and

hydrogenating a portion of the produced condensable hydrocarbons with at least a portion of the produced hydrogen.

1760. The method of claim 1727, wherein allowing the heat to transfer comprises increasing a permeability of a majority of the selected section to greater than about 100 millidarcy.

1761. The method of claim 1727, wherein allowing the heat to transfer comprises substantially uniformly increasing a permeability of a majority of the selected section.

1762. The method of claim 1727, further comprising controlling the heat to yield greater than about 60% by weight of condensable hydrocarbons, as measured by Fischer Assay.

1763. The method of claim 1727, wherein producing the mixture comprises producing the mixture in a production well, and wherein at least about 7 heat sources are disposed in the formation for each production well.

1764. The method of claim 1763, wherein at least about 20 heat sources are disposed in the formation for each production well.

1765. The method of claim 1727, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, and wherein the unit of heat sources comprises a triangular pattern.

1766. The method of claim 1727, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, wherein the unit of heat sources comprises a triangular pattern, and wherein a plurality of the units are repeated over an area of the formation to form a repetitive pattern of units.

1767. A method of treating an oil shale formation in situ, comprising:

providing heat from one or more heat sources to at least a portion of the formation;

allowing the heat to transfer from the one or more heat sources to a selected section of the formation;

wherein at least some hydrocarbons within the selected section have an initial total organic matter weight percentage of at least about 5.0%; and

producing a mixture from the formation.

1768. The method of claim 1767, wherein the one or more heat sources comprise at least two heat sources, and wherein superposition of heat from at least the two heat sources pyrolyzes at least some hydrocarbons within the selected section of the formation.

1769. The method of claim 1767, further comprising maintaining a temperature within the selected section within a pyrolysis temperature range.

1770. The method of claim 1767, wherein the one or more heat sources comprise electrical heaters.

1771. The method of claim 1767, wherein the one or more heat sources comprise surface burners.

1772. The method of claim 1767, wherein the one or more heat sources comprise flameless distributed combustors.

1773. The method of claim 1767, wherein the one or more heat sources comprise natural distributed combustors.

1774. The method of claim 1767, further comprising controlling a pressure and a temperature within at least a majority of the selected section of the formation, wherein the pressure is controlled as a function of temperature, or the temperature is controlled as a function of pressure.

1775. The method of claim 1767, further comprising controlling the heat such that an average heating rate of the selected section is less than about 1° C. per day during pyrolysis.

1776. The method of claim 1767, wherein providing heat from the one or more heat sources to at least the portion of formation comprises:

heating a selected volume (V) of the oil shale formation from the one or more heat sources, wherein the formation has an average heat capacity (Cv), and wherein the heating pyrolyzes at least some hydrocarbons within the selected volume of the formation; and

wherein heating energy/day provided to the volume is equal to or less than Pwr, wherein Pwr is calculated by the equation:

Pwr=h*V*Cv*ρB

wherein Pwr is the heating energy/day, h is an average heating rate of the formation, ρB is formation bulk density, and wherein the heating rate is less than about 10° C./day.

1778. The method of claim 1767, wherein providing heat from the one or more heat sources comprises heating the selected section such that a thermal conductivity of at least a portion of the selected section is greater than about 0.5 W/(m ° C.).

1779. The method of claim 1767, wherein the produced mixture comprises condensable hydrocarbons having an API gravity of at least about 25°.

1780. The method of claim 1767, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 0.1% by weight to about 15% by weight of the condensable hydrocarbons are olefins.

1781. The method of claim 1767, wherein the produced mixture comprises non-condensable hydrocarbons, and wherein a molar ratio of ethene to ethane in the non-condensable hydrocarbons ranges from about 0.001 to about 0.15.

1782. The method of claim 1767, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is nitrogen.

1783. The method of claim 1767, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic If s basis, of the condensable hydrocarbons is oxygen.

1784. The method of claim 1767, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is sulfur.

1785. The method of claim 1767, wherein the produced mixture comprises condensable hydrocarbons, wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons comprise oxygen containing compounds, and wherein the oxygen containing compounds comprise phenols.

1786. The method of claim 1767, wherein the produced mixture comprises condensable hydrocarbons, and wherein greater than about 20% by weight of the condensable hydrocarbons are aromatic compounds.

1787. The method of claim 1767, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 5% by weight of the condensable hydrocarbons comprises multi-ring aromatics with more than two rings.

1788. The method of claim 1767, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 0.3% by weight of the condensable hydrocarbons are asphaltenes.

1789. The method of claim 1767, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons are cycloalkanes.

1790. The method of claim 1767, wherein the produced mixture comprises a non-condensable component, wherein the non-condensable component comprises hydrogen, wherein the hydrogen is greater than about 10% by volume of the non-condensable component, and wherein the hydrogen is less than about 80% by volume of the non-condensable component.

1791. The method of claim 1767, wherein the produced mixture comprises ammonia, do and wherein greater than about 0.05% by weight of the produced mixture is ammonia.

1792. The method of claim 1767, wherein the produced mixture comprises ammonia, and wherein the ammonia is used to produce fertilizer.

1793. The method of claim 1767, further comprising controlling a pressure within at least a majority of the selected section of the formation, wherein the controlled pressure is at least about 2.0 bars absolute.

1794. The method of claim 1767, further comprising controlling formation conditions to produce the mixture, wherein a partial pressure of H2 within the mixture is greater than about 0.5 bars.

1795. The method of claim 1794, wherein the partial pressure of H2 within the mixture is measured when the mixture is at a production well.

1796. The method of claim 1767, further comprising altering a pressure within the formation to inhibit production of hydrocarbons from the formation having carbon numbers greater than about 25.

1797. The method of claim 1767, further comprising controlling formation conditions by recirculating a portion of hydrogen from the mixture into the formation.

1798. The method of claim 1767, further comprising:

providing hydrogen (H2) to the heated section to hydrogenate hydrocarbons within the section; and

heating a portion of the section with heat from hydrogenation.

1799. The method of claim 1767, further comprising:

producing hydrogen and condensable hydrocarbons from the formation; and

hydrogenating a portion of the produced condensable hydrocarbons with at least a portion of the produced hydrogen.

1800. The method of claim 1767, wherein allowing the heat to transfer comprises increasing a permeability of a majority of the selected section to greater than about 100 millidarcy.

1801. The method of claim 1767, wherein allowing the heat to transfer comprises substantially uniformly increasing a permeability of a majority of the selected section.

1802. The method of claim 1767, further comprising controlling the heat to yield greater than about 60% by weight of condensable hydrocarbons, as measured by Fischer Assay.

1803. The method of claim 1767, wherein producing the mixture comprises producing the mixture in a production well, and wherein at least about 7 heat sources are disposed in the formation for each production well.

1804. The method of claim 1803, wherein at least about 20 heat sources are disposed in the formation for each production well.

1805. The method of claim 1767, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, and wherein the unit of heat sources comprises a triangular pattern.

1806. The method of claim 1767, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, wherein the unit of heat sources comprises a triangular pattern, and wherein a plurality of the units are repeated over an area of the formation to form a repetitive pattern of units.

1807. A method of treating an oil shale formation in situ, comprising:

providing heat from one or more heat sources to at least a portion of the formation;

allowing the heat to transfer from the one or more heat sources to a selected section of the formation;

wherein the selected section has been selected for heating using an atomic oxygen weight percentage of at least a portion of hydrocarbons in the selected section, and wherein at least a portion of the hydrocarbons in the selected section comprises an atomic oxygen weight percentage of less than about 15% when measured on a dry, ash free basis; and

producing a mixture from the formation.

1808. The method of claim 1807, wherein the one or more heat sources comprise at least two heat sources, and wherein superposition of heat from at least the two heat sources pyrolyzes at least some hydrocarbons within the selected section of the formation.

1809. The method of claim 1807, further comprising maintaining a temperature within the selected section within a pyrolysis temperature range.

1810. The method of claim 1807, wherein the one or more heat sources comprise electrical heaters.

1811. The method of claim 1807, wherein the one or more heat sources comprise surface burners.

1812. The method of claim 1807, wherein the one or more heat sources comprise flameless distributed combustors.

1813. The method of claim 1807, wherein the one or more heat sources comprise natural distributed combustors.

1814. The method of claim 1807, further comprising controlling a pressure and a temperature within at least a majority of the selected section of the formation, wherein the pressure is controlled as a function of temperature, or the temperature is controlled as a function of pressure.

1815. The method of claim 1807, further comprising controlling the heat such that an average heating rate of the selected section is less than about 1° C. per day during pyrolysis.

1816. The method of claim 1807, wherein providing heat from the one or more heat sources to at least the portion of formation comprises:

heating a selected volume (V) of the oil shale formation from the one or more heat sources, wherein the formation has an average heat capacity (Cv), and wherein the heating pyrolyzes at least some hydrocarbons within the selected volume of the formation; and

wherein heating energy/day provided to the volume is equal to or less than Pwr, wherein Pwr is calculated by the equation:

Pwr=h*V*Cv*ρB

wherein Pwr is the heating energy/day, h is an average heating rate of the formation, ρB is formation bulk density, and wherein the heating rate is less than about 10° C./day.

1818. The method of claim 1807, wherein providing heat from the one or more heat sources comprises heating the selected section such that a thermal conductivity of at least a portion of the selected section is greater than about 0.5 W/(m ° C.).

1819. The method of claim 1807, wherein the produced mixture comprises condensable hydrocarbons having an API gravity of at least about 25°.

1820. The method of claim 1807, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 0.1% by weight to about 15% by weight of the condensable hydrocarbons are olefins.

1821. The method of claim 1807, wherein the produced mixture comprises non-condensable hydrocarbons, and wherein a molar ratio of ethene to ethane in the non-condensable hydrocarbons ranges from about 0.001 to about 0.15.

1822. The method of claim 1807, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is nitrogen.

1823. The method of claim 1807, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is oxygen.

1824. The method of claim 1807, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is sulfur.

1825. The method of claim 1807, wherein the produced mixture comprises condensable hydrocarbons, wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons comprise oxygen containing compounds, and wherein the oxygen containing compounds comprise phenols.

1826. The method of claim 1807, wherein the produced mixture comprises condensable hydrocarbons, and wherein greater than about 20% by weight of the condensable hydrocarbons are aromatic compounds.

1827. The method of claim 1807, wherein the produced mixture comprises condensable o hydrocarbons, and wherein less than about 5% by weight of the condensable hydrocarbons comprises multi-ring aromatics with more than two rings.

1828. The method of claim 1807, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 0.3% by weight of the condensable hydrocarbons are asphaltenes.

1829. The method of claim 1807, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons are cycloalkanes.

1830. The method of claim 1807, wherein the produced mixture comprises a non-condensable component, wherein the non-condensable component comprises hydrogen, wherein the hydrogen is greater than about 10% by volume of the non-condensable component, and wherein the hydrogen is less than about 80% by volume of the non-condensable component.

1831. The method of claim 1807, wherein the produced mixture comprises ammonia, and wherein greater than about 0.05% by weight of the produced mixture is ammonia.

1832. The method of claim 1807, wherein the produced mixture comprises ammonia, and wherein the ammonia is used to produce fertilizer.

1833. The method of claim 1807, further comprising controlling a pressure within at least a majority of the selected section of the formation, wherein the controlled pressure is at least about 2.0 bars absolute.

1834. The method of claim 1807, further comprising controlling formation conditions to produce the mixture, wherein a partial pressure of H2 within the mixture is greater than about 0.5 bars.

1835. The method of claim 1834, wherein the partial pressure of H2 within the mixture is measured when the mixture is at a production well.

1836. The method of claim 1807, further comprising altering a pressure within the formation to inhibit production of hydrocarbons from the formation having carbon numbers greater than about 25.

1837. The method of claim 1807, further comprising controlling formation conditions by recirculating a portion of hydrogen from the mixture into the formation.

1838. The method of claim 1807, further comprising:

providing hydrogen (H2) to the heated section to hydrogenate hydrocarbons within the section; and

heating a portion of the section with heat from hydrogenation.

1839. The method of claim 1807, further comprising:

producing hydrogen and condensable hydrocarbons from the formation; and

hydrogenating a portion of the produced condensable hydrocarbons with at least a portion of the produced hydrogen.

1840. The method of claim 1807, wherein allowing the heat to transfer comprises increasing a permeability of a majority of the selected section to greater than about 100 millidarcy.

1841. The method of claim 1807, wherein allowing the heat to transfer further comprises substantially uniformly increasing a permeability of a majority of the selected section.

1842. The method of claim 1807, further comprising controlling the heat to yield greater than about 60% by weight of condensable hydrocarbons, as measured by Fischer Assay.

1843. The method of claim 1807, wherein producing the mixture comprises producing the mixture in a production well, and wherein at least about 7 heat sources are disposed in the formation for each production well.

1844. The method of claim 1843, wherein at least about 20 heat sources are disposed in the formation for each production well.

1845. The method of claim 1807, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, and wherein the unit of heat sources comprises a triangular pattern.

1846. The method of claim 1807, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, wherein the unit of heat sources comprises a triangular pattern, and wherein a plurality of the units are repeated over an area of the formation to form a repetitive pattern of units.

1847. A method of treating an oil shale formation in situ, comprising:

providing heat from one or more heat sources to a selected section of the formation;

allowing the heat to transfer from the one or more heat sources to the selected section of the formation to pyrolyze hydrocarbon within the selected section;

wherein at least some hydrocarbons within the selected section have an initial atomic oxygen weight percentage of less than about 15%; and

producing a mixture from the formation.

1848. The method of claim 1847, wherein the one or more heat sources comprise at least two heat sources, and wherein superposition of heat from at least the two heat sources pyrolyzes at least some hydrocarbons within the selected section of the formation.

1849. The method of claim 1847, further comprising maintaining a temperature within the selected section within a pyrolysis temperature range

1850. The method of claim 1847, wherein the one or more heat sources comprise electrical heaters.

1851. The method of claim 1847, wherein the one or more heat sources comprise surface burners.

1852. The method of claim 1847, wherein the one or more heat sources comprise flameless distributed combustors.

1853. The method of claim 1847, wherein the one or more heat sources comprise natural distributed combustors.

1854. The method of claim 1847, further comprising controlling a pressure and a temperature within at least a majority of the selected section of the formation, wherein the pressure is controlled as a function of temperature, or the temperature is controlled as a function of pressure.

1855. The method of claim 1847, further comprising controlling the heat such that an average heating rate of the selected section is less than about 1° C. per day during pyrolysis.

1856. The method of claim 1847, wherein providing heat from the one or more heat sources to at least the portion of formation comprises:

heating a selected volume (V) of the oil shale formation from the one or more heat sources, wherein the formation has an average heat capacity (Cv), and wherein the heating pyrolyzes at least some hydrocarbons within the selected volume of the formation; and

wherein heating energy/day provided to the volume is equal to or less than Pwr, wherein Pwr is calculated by the equation:

Pwr=h*V*Cv*ρB

wherein Pwr is the heating energy/day, h is an average heating rate of the formation, ρB is formation bulk density, and wherein the heating rate is less than about 10° C./day.

1858. The method of claim 1847, wherein providing heat from the one or more heat sources comprises heating the selected section such that a thermal conductivity of at least a portion of the selected section is greater than about 0.5 W/(m ° C.).

1859. The method of claim 1847, wherein the produced mixture comprises condensable hydrocarbons having an API gravity of at least about 25°.

1860. The method of claim 1847, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 0.1% by weight to about 15% by weight of the condensable hydrocarbons are olefins.

1861. The method of claim 1847, wherein the produced mixture comprises non-condensable hydrocarbons, and wherein a molar ratio of ethene to ethane in the non-condensable hydrocarbons ranges from about 0.001 to about 0.15.

1862. The method of claim 1847, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is nitrogen.

1863. The method of claim 1847, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is oxygen.

1864. The method of claim 1847, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is sulfur.

1865. The method of claim 1847, wherein the produced mixture comprises condensable hydrocarbons, wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons comprise oxygen containing compounds, and wherein the oxygen containing compounds comprise phenols.

1866. The method of claim 1847, wherein the produced mixture comprises condensable hydrocarbons, and wherein greater than about 20% by weight of the condensable hydrocarbons are aromatic compounds.

1867. The method of claim 1847, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 5% by weight of the condensable hydrocarbons comprises multi-ring aromatics with more than two rings.

1868. The method of claim 1847, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 0.3% by weight of the condensable hydrocarbons are asphaltenes.

1869. The method of claim 1847, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons are cycloalkanes.

1870. The method of claim 1847, wherein the produced mixture comprises a non-condensable component, wherein the non-condensable component comprises hydrogen,

wherein the hydrogen is greater than about 10% by volume of the non-condensable component and wherein the hydrogen is less than about 80% by volume of the non-condensable component.

1871. The method of claim 1847, wherein the produced mixture comprises ammonia, and wherein greater than about 0.05% by weight of the produced mixture is ammonia.

1872. The method of claim 1847, wherein the produced mixture comprises ammonia, and wherein the ammonia is used to produce fertilizer.

1873. The method of claim 1847, further comprising controlling a pressure within at least a majority of the selected section of the formation, wherein the controlled pressure is at least about 2.0 bars absolute.

1874. The method of claim 1847, further comprising controlling formation conditions to produce the mixture, wherein a partial pressure of H2 within the mixture is greater than about 0.5 bars.

1875. The method of claim 1874, wherein the partial pressure of H2 within the mixture is measured when the mixture is at a production well.

1876. The method of claim 1847, further comprising altering a pressure within the formation to inhibit production of hydrocarbons from the formation having carbon numbers greater than about 25.

1877. The method of claim 1847, further comprising controlling formation conditions by recirculating a portion of hydrogen from the mixture into the formation.

1878. The method of claim 1847, further comprising:

providing hydrogen (H2) to the heated section to hydrogenate hydrocarbons within the section; and

heating a portion of the section with heat from hydrogenation.

1879. The method of claim 1847, further comprising:

producing hydrogen and condensable hydrocarbons from the formation; and

hydrogenating a portion of the produced condensable hydrocarbons with at least a portion of the produced hydrogen.

1880. The method of claim 1847, wherein allowing the heat to transfer comprises increasing a permeability of a majority of the selected section to greater than about 100 millidarcy.

1881. The method of claim 1847, wherein allowing the heat to transfer comprises substantially uniformly increasing a permeability of a majority of the selected section.

1882. The method of claim 1847, further comprising controlling the heat to yield greater than about 60% by weight of condensable hydrocarbons, as measured by Fischer Assay.

1883. The method of claim 1847, wherein producing the mixture comprises producing the mixture in a production well, and wherein at least about 7 heat sources are disposed in the formation for each production well.

1884. The method of claim 1883, wherein at least about 20 heat sources are disposed in the formation for each production well.

1885. The method of claim 1847, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, and wherein the unit of heat sources comprises a triangular pattern.

1886. The method of claim 1847, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, wherein the unit of heat sources comprises a triangular pattern, and wherein a plurality of the units are repeated over an area of the formation to form a repetitive pattern of units.

1887. A method of treating an oil shale formation in situ, comprising:

providing heat from one or more heat sources to at least a portion of the formation;

allowing the heat to transfer from the one or more heat sources to a selected section of the formation;

wherein the selected section has been selected for heating using an atomic hydrogen to carbon ratio of at least a portion of hydrocarbons in the selected section, wherein at least a portion of the hydrocarbons in the selected section comprises an atomic hydrogen to carbon ratio greater than about 0.70, and wherein the atomic hydrogen to carbon ratio is less than about 1.65; and

producing a mixture from the formation.

1888. The method of claim 1887, wherein the one or more heat sources comprise at least two heat sources, and wherein superposition of heat from at least the two heat sources pyrolyzes at least some hydrocarbons within the selected section of the formation.

1889. The method of claim 1887, further comprising maintaining a temperature within the selected section within a pyrolysis temperature range.

1890. The method of claim 1887, wherein the one or more heat sources comprise electrical heaters.

1891. The method of claim 1887, wherein the one or more heat sources comprise surface burners.

1892. The method of claim 1887, wherein the one or more heat sources comprise flameless distributed combustors.

1893. The method of claim 1887, wherein the one or more heat sources comprise natural distributed combustors.

1894. The method of claim 1887, further comprising controlling a pressure and a temperature within at least a majority of the selected section of the formation, wherein the pressure is controlled as a function of temperature, or the temperature is controlled as a function of pressure.

1895. The method of claim 1887, further comprising controlling the heat such that an average heating rate of the selected section is less than about 1° C. per day during pyrolysis.

1896. The method of claim 1887, wherein providing heat from the one or more heat sources to at least the portion of formation comprises:

heating a selected volume (V) of the oil shale formation from the one or more heat sources, wherein the formation has an average heat capacity (Cv), and wherein the heating pyrolyzes at least some hydrocarbons within the selected volume of the formation; and

wherein heating energy/day provided to the volume is equal to or less than Pwr, wherein Pwr is calculated by the equation:

Pwr=h*V*Cv*ρB

wherein Pwr is the heating energy/day, h is an average heating rate of the formation, ρB is formation bulk density, and wherein the heating rate is less than about 10° C./day.

1898. The method of claim 1887, wherein providing heat from the one or more heat sources comprises heating the selected section such that a thermal conductivity of at least a portion of the selected section is greater than about 0.5 W/(m ° C.).

1899. The method of claim 1887, wherein the produced mixture comprises condensable hydrocarbons having an API gravity of at least about 25°.

1900. The method of claim 1887, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 0.1% by weight to about 15% by weight of the condensable hydrocarbons are olefins.

1901. The method of claim 1887, wherein the produced mixture comprises non-condensable hydrocarbons, and wherein a molar ratio of ethene to ethane in the non-condensable hydrocarbons ranges from about 0.001 to about 0.15.

1902. The method of claim 1887, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is nitrogen.

1903. The method of claim 1887, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is oxygen.

1904. The method of claim 1887, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is sulfur.

1905. The method of claim 1887, wherein the produced mixture comprises condensable hydrocarbons, wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons comprise oxygen containing compounds, and wherein the oxygen containing compounds comprise phenols.

1906. The method of claim 1887, wherein the produced mixture comprises condensable hydrocarbons, and wherein greater than about 20% by weight of the condensable hydrocarbons are aromatic compounds.

1907. The method of claim 1887, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 5% by weight of the condensable hydrocarbons comprises multi-ring aromatics with more than two rings.

1908. The method of claim 1887, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 0.3% by weight of the condensable hydrocarbons are asphaltenes.

1909. The method of claim 1887, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons are cycloalkanes.

1910. The method of claim 1887, wherein the produced mixture comprises a non-condensable component, wherein the non-condensable component comprises hydrogen, wherein the hydrogen is greater than about 10% by volume of the non-condensable component, and wherein the hydrogen is less than about 80% by volume of the non-condensable component.

1911. The method of claim 1887, wherein the produced mixture comprises ammonia, and wherein greater than about 0.05% by weight of the produced mixture is ammonia.

1912. The method of claim 1887, wherein the produced mixture comprises ammonia, and wherein the ammonia is used to produce fertilizer.

1913. The method of claim 1887, further comprising controlling a pressure within at least a majority of the selected section of the formation, wherein the controlled pressure is at least about 2.0 bars absolute.

1914. The method of claim 1887, further comprising controlling formation conditions to produce the mixture, wherein a partial pressure of H2 within the mixture is greater than about 0.5 bars.

1915. The method of claim 1914, wherein the partial pressure of H2 within the mixture is measured when the mixture is at a production well.

1916. The method of claim 1887, further comprising altering a pressure within the formation to inhibit production of hydrocarbons from the formation having carbon numbers greater than about 25.

1917. The method of claim 1887, further comprising controlling formation conditions by recirculating a portion of hydrogen from the mixture into the formation.

1918. The method of claim 1887, further comprising:

providing hydrogen (H2) to the heated section to hydrogenate hydrocarbons within the section; and

heating a portion of the section with heat from hydrogenation.

1919. The method of claim 1887, further comprising:

producing hydrogen and condensable hydrocarbons from the formation; and

hydrogenating a portion of the produced condensable hydrocarbons with at least a portion of the produced hydrogen.

1920. The method of claim 1887, wherein allowing the heat to transfer comprises increasing a permeability of a majority of the selected section to greater than about 100 millidarcy.

1921. The method of claim 1887, wherein allowing the heat to transfer comprises substantially uniformly increasing a permeability of a majority of the selected section.

1922. The method of claim 1887, further comprising controlling the heat to yield greater than about 60% by weight of condensable hydrocarbons, as measured by Fischer Assay.

1923. The method of claim 1887, wherein producing the mixture comprises producing the mixture in a production well, and wherein at least about 7 heat sources are disposed in the formation for each production well.

1924. The method of claim 1923, wherein at least about 20 heat sources are disposed in the formation for each production well.

1925. The method of claim 1887, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, and wherein the unit of heat sources comprises a triangular pattern.

1926. The method of claim 1887, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, wherein the unit of heat sources comprises a triangular pattern, and wherein a plurality of the units are repeated over an area of the formation to form a repetitive pattern of units.

1927. A method of treating an oil shale formation in situ, comprising:

providing heat from one or more heat sources to a selected section of the formation;

allowing the heat to transfer from the one or more heat sources to the selected section of the formation to pyrolyze hydrocarbons within the selected section;

wherein at least some hydrocarbons within the selected section have an initial atomic hydrogen to carbon ratio greater than about 0.70;

wherein the initial atomic hydrogen to carbon ratio is less than about 1.65; and

producing a mixture from the formation.

1928. The method of claim 1927, wherein the one or more heat sources comprise at least two heat sources, and wherein superposition of heat from at least the two heat sources pyrolyzes at least some hydrocarbons within the selected section of the formation.

1929. The method of claim 1927, further comprising maintaining a temperature within the selected section within a pyrolysis temperature range.

1930. The method of claim 1927, wherein the one or more heat sources comprise electrical heaters.

1931. The method of claim 1927, wherein the one or more heat sources comprise surface burners.

1932. The method of claim 1927, wherein the one or more heat sources comprise flameless distributed combustors.

1933. The method of claim 1927, wherein the one or more heat sources comprise natural distributed combustors.

1934. The method of claim 1927, further comprising controlling a pressure and a temperature within at least a majority of the selected section of the formation, wherein the pressure is controlled as a function of temperature, or the temperature is controlled as a function of pressure.

1935. The method of claim 1927, further comprising controlling the heat such that an average heating rate of the selected section is less than about 1° C. per day during pyrolysis.

1936. The method of claim 1927, wherein providing heat from the one or more heat sources to at least the portion of formation comprises:

heating a selected volume (V) of the oil shale formation from the one or more heat sources, wherein the formation has an average heat capacity (Cv), and wherein the heating pyrolyzes at least some hydrocarbons within the selected volume of the formation; and

wherein heating energy/day provided to the volume is equal to or less than Pwr, wherein Pwr is calculated by the equation:

Pwr=h*V*Cv*ρB

wherein Pwr is the heating energy/day, h is an average heating rate of the formation, ρB is formation bulk density, and wherein the heating rate is less than about 10° C./day.

1938. The method of claim 1927, wherein providing heat from the one or more heat sources comprises heating the selected section such that a thermal conductivity of at least a portion of the selected section is greater than about 0.5 W/(m ° C.).

1939. The method of claim 1927, wherein the produced mixture comprises condensable hydrocarbons having an API gravity of at least about 25°.

1940. The method of claim 1927, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 0.1% by weight to about 15% by weight of the condensable hydrocarbons are olefins.

1941. The method of claim 1927, wherein the produced mixture comprises non-condensable hydrocarbons, and wherein a molar ratio of ethene to ethane in the non-condensable hydrocarbons ranges from about 0.001 to about 0.15.

1942. The method of claim 1927, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is nitrogen.

1943. The method of claim 1927, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is oxygen.

1944. The method of claim 1927, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is sulfur.

1945. The method of claim 1927, wherein the produced mixture comprises condensable hydrocarbons, wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons comprise oxygen containing compounds, and wherein the oxygen containing compounds comprise phenols.

1946. The method of claim 1927, wherein the produced mixture comprises condensable hydrocarbons, and wherein greater than about 20% by weight of the condensable hydrocarbons are aromatic compounds.

1947. The method of claim 1927, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 5% by weight of the condensable hydrocarbons comprises multi-ring aromatics with more than two rings.

1948. The method of claim 1927, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 0.3% by weight of the condensable hydrocarbons are asphaltenes.

1949. The method of claim 1927, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons are cycloalkanes.

1950. The method of claim 1927, wherein the produced mixture comprises a non-condensable component, wherein the non-condensable component comprises hydrogen, wherein the hydrogen is greater than about 10% by volume of the non-condensable component, and wherein the hydrogen is less than about 80% by volume of the non-condensable component.

1951. The method of claim 1927, wherein the produced mixture comprises ammonia, and wherein greater than about 0.05% by weight of the produced mixture is ammonia.

1952. The method of claim 1927, wherein the produced mixture comprises ammonia, and wherein the ammonia is used to produce fertilizer.

1953. The method of claim 1927, further comprising controlling a pressure within at least a majority of the selected section of the formation, wherein the controlled pressure is at least about 2.0 bars absolute.

1954. The method of claim 1927, further comprising controlling formation conditions to produce the mixture, wherein a partial pressure of H2 within the mixture is greater than about 0.5 bars.

1955. The method of claim 1954, wherein the partial pressure of H2 within the mixture is measured when the mixture is at a production well.

1956. The method of claim 1927, further comprising altering a pressure within the formation to inhibit production of hydrocarbons from the formation having carbon numbers greater than about 25.

1957. The method of claim 1927, further comprising controlling formation conditions by recirculating a portion of hydrogen from the mixture into the formation.

1958. The method of claim 1927, further comprising:

providing hydrogen (H2) to the heated section to hydrogenate hydrocarbons within the section; and

heating a portion of the section with heat from hydrogenation.

1959. The method of claim 1927, further comprising:

producing hydrogen and condensable hydrocarbons from the formation; and

hydrogenating a portion of the produced condensable hydrocarbons with at least a portion of the produced hydrogen.

1960. The method of claim 1927, wherein allowing the heat to transfer comprises increasing a permeability of a majority of the selected section to greater than about 100 millidarcy.

1961. The method of claim 1927, wherein allowing the heat to transfer comprises substantially uniformly increasing a permeability of a majority of the selected section.

1962. The method of claim 1927, further comprising controlling the heat to yield greater than about 60% by weight of condensable hydrocarbons, as measured by Fischer Assay.

1963. The method of claim 1927, wherein producing the mixture comprises producing the mixture in a production well, and wherein at least about 7 heat sources are disposed in the formation for each production well.

1964. The method of claim 1963, wherein at least about 20 heat sources are disposed in the formation for each production well.

1965. The method of claim 1927, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, and wherein the unit of heat sources comprises a triangular pattern.

1966. The method of claim 1927, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, wherein the unit of heat sources comprises a triangular pattern, and wherein a plurality of the units are repeated over an area of the formation to form a repetitive pattern of units.

1967. A method of treating an oil shale formation in situ, comprising:

providing heat from one or more heat sources to at least a portion of the formation;

allowing the heat to transfer from the one or more heat sources to a selected section of the formation;

wherein the selected section has been selected for heating using an atomic oxygen to carbon ratio of at least a portion of hydrocarbons in the selected section, wherein at least a portion of the hydrocarbons in the selected section comprises an atomic oxygen to carbon ratio greater than about 0.025, and wherein the atomic oxygen to carbon ratio of at least a portion of the hydrocarbons in the selected section is less than about 0.15; and

producing a mixture from the formation.

1968. The method of claim 1967, wherein the one or more heat sources comprise at least two heat sources, and wherein superposition of heat from at least the two heat sources pyrolyzes at least some hydrocarbons within the selected section of the formation.

1969. The method of claim 1967, further comprising maintaining a temperature within the selected section within a pyrolysis temperature range.

1970. The method of claim 1967, wherein the one or more heat sources comprise electrical heaters.

1971. The method of claim 1967, wherein the one or more heat sources comprise surface burners.

1972. The method of claim 1967, wherein the one or more heat sources comprise flameless distributed combustors.

1973. The method of claim 1967, wherein the one or more heat sources comprise natural distributed combustors.

1974. The method of claim 1967, further comprising controlling a pressure and a temperature within at least a majority of the selected section of the formation, wherein the pressure is controlled as a function of temperature, or the temperature is controlled as a function of pressure.

1975. The method of claim 1967, further comprising controlling the heat such that an average heating rate of the selected section is less than about 1° C. per day during pyrolysis.

1976. The method of claim 1967, wherein providing heat from the one or more heat sources to at least the portion of formation comprises.

heating a selected volume (V) of the oil shale formation from the one or more heat sources, wherein the formation has an average heat capacity (Cv), and wherein the heating pyrolyzes at least some hydrocarbons within the selected volume of the formation; and

wherein heating energy/day provided to the volume is equal to or less than Pwr, wherein Pwr is calculated by the equation:

Pwr=h*V*Cv*ρB

wherein Pwr is the heating energy/day, h is an average heating rate of the formation, ρB is formation bulk density, and wherein the heating rate is less than about 10° C./day.

1978. The method of claim 1967, wherein providing heat from the one or more heat sources comprises heating the selected section such that a thermal conductivity of at least a portion of the selected section is greater than about 0.5 W/(m ° C.).

1979. The method of claim 1967, wherein the produced mixture comprises condensable hydrocarbons having an API gravity of at least about 25°.

1980. The method of claim 1967, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 0.1% by weight to about 15% by weight of the condensable hydrocarbons are olefins.

1981. The method of claim 1967, wherein the produced mixture comprises non-condensable hydrocarbons, and wherein a molar ratio of ethene to ethane in the non-condensable hydrocarbons ranges from about 0.001 to about 0.15.

1982. The method of claim 1967, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is nitrogen.

1983. The method of claim 1967, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is oxygen.

1984. The method of claim 1967, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is sulfur.

1985. The method of claim 1967, wherein the produced mixture comprises condensable hydrocarbons, wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons comprise oxygen containing compounds, and wherein the oxygen containing compounds comprise phenols.

1986. The method of claim 1967, wherein the produced mixture comprises condensable hydrocarbons, and wherein greater than about 20% by weight of the condensable hydrocarbons are aromatic compounds.

1987. The method of claim 1967, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 5% by weight of the condensable hydrocarbons comprises multi-ring aromatics with more than two rings.

1988. The method of claim 1967, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 0.3% by weight of the condensable hydrocarbons are asphaltenes.

1989. The method of claim 1967, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons are cycloalkanes.

1990. The method of claim 1967, wherein the produced mixture comprises a non-condensable component, wherein the non-condensable component comprises hydrogen, wherein the hydrogen is greater than about 10% by volume of the non-condensable component, and wherein the hydrogen is less than about 80% by volume of the non-condensable component.

1991. The method of claim 1967, wherein the produced mixture comprises ammonia, and wherein greater than about 0.05% by weight of the produced mixture is ammonia.

1992. The method of claim 1967, wherein the produced mixture comprises ammonia, and wherein the ammonia is used to produce fertilizer.

1993. The method of claim 1967, further comprising controlling a pressure within at least a majority of the selected section of the formation, wherein the controlled pressure is at least about 2.0 bars absolute.

1994. The method of claim 1967, further comprising controlling formation conditions to produce the mixture, wherein a partial pressure of H2 within the mixture is greater than about 0.5 bars.

1995. The method of claim 1994, wherein the partial pressure of H2 within the mixture is measured when the mixture is at a production well.

1996. The method of claim 1967, further comprising altering a pressure within the formation to inhibit production of hydrocarbons from the formation having carbon numbers greater than about 25.

1997. The method of claim 1967, further comprising controlling formation conditions by recirculating a portion of hydrogen from the mixture into the formation.

1998. The method of claim 1967, further comprising:

providing hydrogen (H2) to the heated section to hydrogenate hydrocarbons within the section; and

heating a portion of the section with heat from hydrogenation.

1999. The method of claim 1967, further comprising:

producing hydrogen and condensable hydrocarbons from the formation; and

hydrogenating a portion of the produced condensable hydrocarbons with at least a portion of the produced hydrogen.

2000. The method of claim 1967, wherein allowing the heat to transfer comprises increasing a permeability of a majority of the selected section to greater than about 100 millidarcy.

2001. The method of claim 1967, wherein allowing the heat to transfer further comprises substantially uniformly increasing a permeability of a majority of the selected section.

2002. The method of claim 1967, further comprising controlling the heat to yield greater than about 60% by weight of condensable hydrocarbons, as measured by Fischer Assay.

2003. The method of claim 1967, wherein producing the mixture comprises producing the mixture in a production well, and wherein at least about 7 heat sources are disposed in the formation for each production well.

2004. The method of claim 2003, wherein at least about 20 heat sources are disposed in the formation for each production well.

2005. The method of claim 1967, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, and wherein the unit of heat sources comprises a triangular pattern.

2006. The method of claim 1967, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, wherein the unit of heat sources comprises a triangular pattern, and wherein a plurality of the units are repeated over an area of the formation to form a repetitive pattern of units.

2007. A method of treating an oil shale formation in situ, comprising

providing heat from one or more heat sources to a selected section of the formation;

allowing the heat to transfer from the one or more heat sources to the selected section of the formation to pyrolyze hydrocarbons within the selected section;

wherein at least some hydrocarbons within the selected section have an initial atomic oxygen to carbon ratio greater than about 0.025;

wherein the initial atomic oxygen to carbon ratio is less than about 0.15; and

producing a mixture from the formation.

2008. The method of claim 2007, wherein the one or more heat sources comprise at least two heat sources, and wherein superposition of heat from at least the two heat sources pyrolyzes at least some hydrocarbons within the selected section of the formation.

2009. The method of claim 2007, further comprising maintaining a temperature within the selected section within a pyrolysis temperature range.

2010. The method of claim 2007, wherein the one or more heat sources comprise electrical heaters.

2011. The method of claim 2007, wherein the one or more heat sources comprise surface burners.

2012. The method of claim 2007, wherein the one or more heat sources comprise flameless distributed combustors.

2013. The method of claim 2007, wherein the one or more heat sources comprise natural distributed combustors.

2014. The method of claim 2007, further comprising controlling a pressure and a temperature within at least a majority of the selected section of the formation, wherein the pressure is controlled as a function of temperature, or the temperature is controlled as a function of pressure.

2015. The method of claim 2007, further comprising controlling the heat such that an average heating rate of the selected section is less than about 1° C. per day during pyrolysis.

2016. The method of claim 2007, wherein providing heat from the one or more heat sources to at least the portion of formation comprises:

heating a selected volume (V) of the oil shale formation from the one or more heat sources, wherein the formation has an average heat capacity (Cv), and wherein the heating pyrolyzes at least some hydrocarbons within the selected volume of the formation; and

wherein heating energy/day provided to the volume is equal to or less than Pwr, wherein Pwr is calculated by the equation:

Pwr=h*V*Cv*ρB

wherein Pwr is the heating energy/day, h is an average heating rate of the formation, ρB is formation bulk density, and wherein the heating rate is less than about 10° C./day.

2018. The method of claim 2007, wherein providing heat from the one or more heat sources comprises heating the selected section such that a thermal conductivity of at least a portion of the selected section is greater than about 0.5 W/(m ° C.).

2019. The method of claim 2007, wherein the produced mixture comprises condensable hydrocarbons having an API gravity of at least about 25°.

2020. The method of claim 2007, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 0.1% by weight to about 15% by weight of the condensable hydrocarbons are olefins.

2021. The method of claim 2007, wherein the produced mixture comprises non-condensable hydrocarbons, and wherein a molar ratio of ethene to ethane in the non-condensable hydrocarbons ranges from about 0.001 to about 0.15.

2022. The method of claim 2007, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is nitrogen.

2023. The method of claim 2007, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is oxygen.

2024. The method of claim 2007, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 1% by weight, when calculated on an atomic basis, of the condensable hydrocarbons is sulfur.

2025. The method of claim 2007, wherein the produced mixture comprises condensable hydrocarbons, wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons comprise oxygen containing compounds, and wherein the oxygen containing compounds comprise phenols.

2026. The method of claim 2007, wherein the produced mixture comprises condensable hydrocarbons, and wherein greater than about 20% by weight of the condensable hydrocarbons are aromatic compounds.

2027. The method of claim 2007, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 5% by weight of the condensable hydrocarbons comprises multi-ring aromatics with more than two rings.

2028. The method of claim 2007, wherein the produced mixture comprises condensable hydrocarbons, and wherein less than about 0.3% by weight of the condensable hydrocarbons are asphaltenes.

2029. The method of claim 2007, wherein the produced mixture comprises condensable hydrocarbons, and wherein about 5% by weight to about 30% by weight of the condensable hydrocarbons are cycloalkanes.

2030. The method of claim 2007, wherein the produced mixture comprises a non-condensable component, wherein the non-condensable component comprises hydrogen, wherein the hydrogen is greater than about 10% by volume of the non-condensable component, and wherein the hydrogen is less than about 80% by volume of the non-condensable component.

2031. The method of claim 2007, wherein the produced mixture comprises ammonia, and wherein greater than about 0.05% by weight of the produced mixture is ammonia.

2032. The method of claim 2007, wherein the produced mixture comprises ammonia, and wherein the ammonia is used to produce fertilizer.

2033. The method of claim 2007, further comprising controlling a pressure within at least a majority of the selected section of the formation, wherein the controlled pressure is at least about 2.0 bars absolute.

2034. The method of claim 2007, further comprising controlling formation conditions to produce the mixture, wherein a partial pressure of H2 within the mixture is greater than about 0.5 bars.

2035. The method of claim 2034, wherein the partial pressure of H2 within the mixture is measured when the mixture is at a production well.

2036. The method of claim 2007, further comprising altering a pressure within the formation to inhibit production of hydrocarbons from the formation having carbon numbers greater than about 25.

2037. The method of claim 2007, further comprising controlling formation conditions by recirculating a portion of hydrogen from the mixture into the formation.

2038. The method of claim 2007, further comprising:

providing hydrogen (H2) to the heated section to hydrogenate hydrocarbons within the section; and

heating a portion of the section with heat from hydrogenation.

2039. The method of claim 2007, further comprising:

producing hydrogen and condensable hydrocarbons from the formation; and

hydrogenating a portion of the produced condensable hydrocarbons with at least a portion of the produced hydrogen.

2040. The method of claim 2007, wherein allowing the heat to transfer comprises increasing a permeability of a majority of the selected section to greater than about 100 millidarcy.

2041. The method of claim 2007, wherein allowing the heat to transfer further comprises substantially uniformly increasing a permeability of a majority of the selected section.

2042. The method of claim 2007, further comprising controlling the heat to yield greater than about 60% by weight of condensable hydrocarbons, as measured by Fischer Assay.

2043. The method of claim 2007, wherein producing the mixture comprises producing the mixture in a production well, and wherein at least about 7 heat sources are disposed in the formation for each production well.

2044. The method of claim 2043, wherein at least about 20 heat sources are disposed in the formation for each production well.

2045. The method of claim 2007, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, and wherein the unit of heat sources comprises a triangular pattern.

2046. The method of claim 2007, further comprising providing heat from three or more heat sources to at least a portion of the formation, wherein three or more of the heat sources are located in the formation in a unit of heat sources, wherein the unit of heat sources comprises a triangular pattern, and wherein a plurality of the units are repeated over an area of the formation to form a repetitive pattern of units.

2047. A method of treating an oil shale formation in situ, comprising:

providing heat from one or more heat sources to at least a portion of the formation;

allowing the heat to transfer from the one or more heat sources to a selected section of the formation;

wherein the selected section has been selected for heating using a moisture content in the selected section, and wherein at least a portion of the selected section comprises a moisture content of less than about 15% by weight; and

producing a mixture from the formation.

2048. The method of claim 2047, wherein the one or more heat sources comprise at least two heat sources, and wherein superposition of heat from at least the two heat sources pyrolyzes at least some hydrocarbons within the selected section of the formation.

2049. The method of claim 2047, further comprising maintaining a temperature within the selected section within a pyrolysis temperature range.

2050. The method of claim 2047, wherein the one or more heat sources comprise electrical heaters.

2051. The method of claim 2047, wherein the one or more heat sources comprise surface burners.

2052. The method of claim 2047, wherein the one or more heat sources comprise flameless distributed combustors.

2053. The method of claim 2047, wherein the one or more heat sources comprise natural distributed combustors.

2054. The method of claim 2047, further comprising controlling a pressure and a temperature within at least a majority of the selected section of the formation, wherein the pressure is controlled as a function of temperature, or the temperature is controlled as a function of pressure.